Advanced Power Plant Materials, Design and Technology (Woodhead Publishing Series in Energy)

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Advanced power plant materials, design and technology

© Woodhead Publishing Limited, 2010

Related titles: Developments and innovation in carbon dioxide (CO2) capture and storage technology: Volume 1 Carbon dioxide (CO2) capture, transport and industrial applications (ISBN 978-1-84569-533-0) Volume 2 Carbon dioxide (CO2) storage and utilisation (ISBN 978-1-84569-797-6) Carbon dioxide (CO2) capture and storage (CCS) is the one advanced technology that conventional power generation cannot do without. CCS technology reduces the carbon footprint of power plants by capturing and storing the CO2 emissions from burning fossil fuels and biomass. Capture technology ranges from post- and pre-combustion capture to combustion-based capture. Storage options range from geological sequestration in deep saline aquifers and utilisation of CO2 for enhanced oil and gas recovery, to mineral carbonation and biofixation of CO2. Volume 1 critically reviews carbon capture processes and technology applicable to the conventional power generation sector as well as other high-carbon-footprint industries. Volume 2 reviews carbon storage and utilisation, covering all the main geological, terrestrial and ocean sequestration options and their environmental impacts, as well as other advanced concepts such as utilisation and photocatalytic reduction. Generating power at high efficiency: Combined cycle technology for sustainable energy production (ISBN 978-1-84569-433-3) Combined cycle technology is used to generate power at one of the highest levels of efficiency of conventional power plants. It does this through primary generation from a gas turbine coupled with secondary generation from a steam turbine powered by primary exhaust heat. Generating power at high efficiency thoroughly charts the development and implementation of this technology in power plants and looks to the future of the technology, noting the advantages of the most important technical features – including gas turbine, steam generator, combined heat and power and integrated gasification combined cycle (IGCC) – with their latest applications. Details of these and other Woodhead Publishing materials books can be obtained by: . .

visiting our web site at www.woodheadpublishing.com contacting Customer Services (e-mail: [email protected]; fax: +44 (0) 1223 893694; tel.: +44 (0) 1223 891358 ext. 130; address: Woodhead Publishing Limited, Abington Hall, Granta Park, Great Abington, Cambridge CB21 6AH, UK)

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Woodhead Publishing Series in Energy: Number 5

Advanced power plant materials, design and technology Edited by Dermot Roddy

CRC Press Boca Raton Boston New York Washington, DC

WOODHEAD

PUBLISHING LIMITED Oxford Cambridge New Delhi


Published by Woodhead Publishing Limited, Abington Hall, Granta Park, Great Abington, Cambridge CB21 6AH, UK www.woodheadpublishing.com Woodhead Publishing India Private Limited, G-2, Vardaan House, 7/28 Ansari Road, Daryaganj, New Delhi – 110002, India www.woodheadpublishingindia.com Published in North America by CRC Press LLC, 6000 Broken Sound Parkway, NW, Suite 300, Boca Raton, FL 33487, USA First published 2010, Woodhead Publishing Limited and CRC Press LLC # Woodhead Publishing Limited, 2010 The authors have asserted their moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the authors and the publishers cannot assume responsibility for the validity of all materials. Neither the authors nor the publishers, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. Library of Congress Cataloging in Publication Data A catalog record for this book is available from the Library of Congress. Woodhead Publishing ISBN 978-1-84569-515-6 (book) Woodhead Publishing ISBN 978-1-84569-946-8 (e-book) CRC Press ISBN 978-1-4398-2727-7 CRC Press order number: N10145 The publishers’ policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acid-free and elemental chlorine-free practices. Furthermore, the publishers ensure that the text paper and cover board used have met acceptable environmental accreditation standards. Typeset by Data Standards Ltd, Frome, Somerset, UK Printed by TJ International Limited, Padstow, Cornwall, UK


Contents

Contributor contact details

xi

Woodhead Publishing Series in Energy

xv

Preface

xvii

Part I

Advanced power plant materials and designs

1

Advanced gas turbine materials, design and technology J. FADOK, Siemens Energy Inc., USA

3

1.1 1.2

Introduction Development of materials and coatings for gas turbines and turbine components Higher temperature efficiency operation Design for hydrogen-rich gases Design to run at variable generation rates Future trends Sources of further information References

3

1.3 1.4 1.5 1.6 1.7 1.8 2

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Gas-fired combined-cycle power plant design and technology A. D. RAO, University of California, USA

8 15 21 26 29 30 31 32

Introduction 32 Plant design and technology 36 Applicable criteria pollutants control technologies 41 CO2 emissions control technologies 42 Advantages and limitations of gas-fired combined-cycle plants 46 Future trends 48 Sources of further information 52 References 52


vi

Contents

3

Integrated gasification combined cycle (IGCC) power plant design and technology Y. ZHU, Pacific Northwest National Laboratory, USA; and H. C. FREY, North Carolina State University, USA

3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 4

4.1 4.2 4.3 4.4 4.5

4.6 4.7 4.8

Introduction: types of integrated gasification combined cycle (IGCC) plants IGCC plant design and main processes technologies Applicable CO2 capture technologies Applicable emissions control technologies Advantages and limitations of coal IGCC plants Future trends Sources of further information References Improving thermal cycle efficiency in advanced power plants: water and steam chemistry and materials performance B. DOOLEY, Structural Integrity Associates, Inc., USA; and R. SVOBODA, Svoboda Consulting, Switzerland Introduction Key characteristics of advanced thermal power cycles Volatility, partitioning and solubility Deposits and corrosion in the thermal cycle of a power plant Water and steam chemistry in the thermal cycle with particular emphasis on supercritical and ultra-supercritical plant Challenges for future ultra-supercritical power cycles Acknowledgement References

54

54 60 67 69 75 79 83 83

89

89 91 93 94

100 105 107 107

Part II Gas separation membranes, emissions handling, and instrumentation and control technology for advanced power plants 5

5.1 5.2 5.3 5.4 5.5 5.6

Advanced hydrogen (H2) gas separation membrane development for power plants S. J. DOONG, UOP, a Honeywell Company, USA

111

Introduction Hydrogen membrane materials Membrane system design and performance Hydrogen membrane integration with power plant Hydrogen storage and transportation Future trends

111 113 121 125 132 133


Contents 5.7 5.8

Sources of further information and advice References

6

Advanced carbon dioxide (CO2) gas separation membrane development for power plants A. BASILE, Italian National Research Council, Italy; F. GALLUCCI, University of Twente, The Netherlands; and P. MORRONE, University of Calabria, Italy

vii 135 135 143

6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8

Introduction Performance of membrane system CO2 membrane materials and design Membrane modules Design for power plant integration Cost considerations Sources of further information References

143 148 156 161 169 175 178 181

7

Advanced flue gas cleaning systems for sulfur oxides (SOx ), nitrogen oxides (NOx ) and mercury emissions control in power plants S. FALCONE MILLER and B. G. MILLER, The Pennsylvania State University, USA

187

7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9

Introduction Flue gas desulfurization (FGD) Selective catalytic reduction (SCR) Selective non-catalytic reduction (SNCR) Hybrid SNCR/SCR Activated carbon injection systems Future trends Sources of further information References

187 189 203 207 208 209 212 215 215

8

Advanced flue gas dedusting systems and filters for ash and particulate emissions control in power plants B. G. MILLER, The Pennsylvania State University, USA

217

Introduction Materials, design, and development for particulate control Electrostatic precipitators (ESPs) Fabric filters Future trends Sources of further information References

217 219 219 229 236 241 242

8.1 8.2 8.3 8.4 8.5 8.6 8.7


viii

Contents

9

Advanced sensors for combustion monitoring in power plants: towards smart high-density sensor networks 244 M. YU and A. K. GUPTA, University of Maryland, USA; and M. BRYDEN, Iowa State University, USA

9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9

Introduction Combustion behavior Sensor considerations Sensor response Vision of smart sensor networks Sensor information processing Conclusions Acknowledgements References

244 246 248 251 255 260 261 262 262

10

Advanced monitoring and process control technology for coal-fired power plants Y. YAN, University of Kent, UK

264

Introduction Advanced sensors for on-line monitoring and measurement Advanced control Future trends Sources of further information References

264 266 279 282 284 285

10.1 10.2 10.3 10.4 10.5 10.6

Part III Improving the fuel flexibility, environmental impact and generation performance of advanced power plants 11

Low-rank coal properties, upgrading and utilization for improving the fuel flexibility of advanced power plants 291 T. DLOUHY´, Czech Technical University in Prague, Czech Republic

11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8 11.9 11.10

Introduction Properties of low-rank coal Influence on design and efficiency of boilers Low-rank coal preparation Technologies of low-rank coal upgrading Utilization of low-rank coal in advanced power plants Future trends in coal upgrading Sources of further information Acknowledgement References


291 292 294 294 296 305 307 309 310 310

Contents 12

Biomass resources, fuel preparation and utilization for improving the fuel flexibility of advanced power plants L. ROSENDAHL, Aalborg University, Denmark

12.1 12.2 12.3 12.4 12.5 12.6 12.7

Introduction Biomass types and conversion technologies Chemical constituents in biomass fuels Physical preparation of biomass fuels Functional biomass mixes Summary References

13

Development and integration of underground coal gasification (UCG) for improving the environmental impact of advanced power plants M. GREEN, UCG Engineering Ltd, UK

13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 13.10 13.11 13.12

Introduction Brief history of UCG The UCG process Criteria for siting and geology Drilling technologies and well construction for UCG Integration with power plant Environmental issues and benefits Future trends Conclusion and future trends Sources of further information Glossary References

14

Development and application of carbon dioxide (CO2) storage for improving the environmental impact of advanced power plants B. MCPHERSON, The University of Utah, USA

14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9

Introduction Premise: capture and sequestration of CO2 from power plants Fundamentals of subsurface CO2 flow and transport Fundamentals of subsurface CO2 storage Enhanced oil/gas and coalbed methane recovery CO2 storage in deep saline formations Comparison of storage options: oil/gas versus coal versus deep saline General site selection criteria Emissions versus potential subsurface storage capacity


ix

312 312 316 320 324 329 330 330

332 332 334 335 341 344 346 350 354 358 359 360 361

364 364 365 366 368 371 372 372 373 375

x

Contents

14.10 14.11 14.12 14.13 14.14

Sealing and monitoring to ensure CO2 containment Alternatives to geologic storage Future trends Sources of further information and advice References

376 376 377 379 379

15

Advanced technologies for syngas and hydrogen (H2) production from fossil-fuel feedstocks in power plants P. CHIESA, Politecnico di Milano, Italy

383

Introduction Syngas production from gas and light liquids Syngas conversion and purification Syngas and hydrogen from heavy feedstocks Thermal balance of hydrogen production processes Future trends Sources of further information References

383 383 393 399 403 408 409 410

Index

412

15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8



(* = main contact)

Chapter 3

Editor

Y. Zhu Energy and Environmental Directorate Pacific Northwest National Laboratory 902 Battelle Boulevard Richland Washington 99354 USA Email: [email protected]

D. Roddy Science City Professor of Energy Director, Sir Joseph Swan Institute Floor 3, Devonshire Building Newcastle University Newcastle upon Tyne NE1 7RU Email: [email protected]

Chapter 1 J. Fadok Project Director, Gas Turbine Engineering Siemens Energy, Inc. 4400 Alafaya Trail MS Q3-039 Orlando, Florida 32826 Email: [email protected]

Chapter 2 A. D. Rao Advanced Power and Energy Program University of California Irvine, California 92697 USA Email: [email protected]

H. C. Frey* Department of Civil, Construction, and Environmental Engineering North Carolina State University Raleigh North Carolina 27695-7908 USA Email: [email protected]

Chapter 4 B. Dooley* Structural Integrity Associates, Inc. 2616 Chelsea Drive Charlotte, NC 28209 USA Email: [email protected] R. Svoboda Svoboda Consulting


xii


Rosenauweg 9A CH-5430 Wettingen, Switzerland Email: [email protected]

Chapter 5 S. J. Doong UOP, a Honeywell Company 25 East Algonquin Road Des Plaines, 60017 USA Email: [email protected]

Chapter 6 A. Basile* Institute of Membrane Technology Italian National Research Council Italy Email: [email protected] F. Gallucci Fundamentals of Chemical Reaction Engineering Department IMPACT University of Twente Enschede The Netherlands P. Morrone Department of Mechanical Engineering University of Calabria Rende (CS) Italy

Chapter 7 S. Falcone Miller* EMS Energy Institute The Pennsylvania State University 407 Academic Activities Building

University Park, PA 16802 Email: [email protected] B. G. Miller EMS Energy Institute The Pennsylvania State University C214 Coal Utilization Laboratory University Park, PA 16802 Email: [email protected]

Chapter 8 B. G. Miller EMS Energy Institute The Pennsylvania State University C214 Coal Utilization Laboratory University Park, PA 16802 Email: [email protected]

Chapter 9 M. Yu and A. K. Gupta* University of Maryland College Park MD 20742 USA Email: [email protected] M. Bryden Iowa State University Ames Iowa IA 50011 USA

Chapter 10 Y. Yan Instrumentation, Control and Embedded Systems Group School of Engineering and Digital Arts University of Kent Canterbury


Contributor contact details Kent CT2 7NT UK Email: [email protected]

Chapter 11 T. Dlouhy´ Czech Technical University in Prague Faculty of Mechanical Engineering Technicka´ 4 Prague 6 166 07 Czech Republic Email: [email protected]

Chapter 12 L. Rosendahl Department of Energy Technology Aalborg University Pontoppidanstræde 101 DK-9220 Aalborg Denmark Email: [email protected]

Chapter 13

xiii

29/30 Fitzroy Square London W1T 6LQ UK Email: [email protected]

Chapter 14 B. McPherson Department of Civil and Environmental Engineering The University of Utah Salt Lake City Utah 84112 USA Email: [email protected]

Chapter 15 P. Chiesa Department of Energy Politecnico di Milano Via Lambruschini, 4 20156 Milan Italy Email: [email protected]

M. Green Founding Director UCG Engineering Ltd



1

Generating power at high efficiency: Combined cycle technology for sustainable energy production Eric Jeffs

2

Advanced separation techniques for nuclear fuel reprocessing and radioactive waste treatment Edited by Kenneth L. Nash and Gregg J. Lumetta

3

Bioalcohol production: Biochemical conversion of lignocellulosic biomass Edited by Keith Waldron

4

Understanding and mitigating ageing in nuclear power plants: Materials and operational aspects of plant life management (PLiM) Edited by Philip G. Tipping

5

Advanced power plant materials, design and technology Edited by Dermot Roddy

6

Stand-alone and hybrid wind energy systems: Technology, energy storage and applications Edited by J. K. Kaldellis

7

Biodiesel science and technology: From soil to oil Jan C. J. Bart, Natale Palmeri and Stefano Cavallaro

8

Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 1: Carbon dioxide (CO2) capture, transport and industrial applications Edited by M. Mercedes Maroto-Valer

9

Geological repository systems for safe disposal of spent nuclear fuels and radioactive waste Edited by Joonhong Ahn and Mick Apted


xvi


10 Wind energy systems: Optimising design and construction for safe and reliable operation Edited by John Dalsgaard Sørensen and Jens Nørkær Sørensen 11 Solid oxide fuel cell technology: Principles, performance and operations Kevin Huang and John Bannister Goodenough 12 Handbook of advanced radioactive waste conditioning technologies Edited by Michael I. Ojovan 13 Nuclear reactor safety systems Edited by Dan Gabriel Cacuci 14 Materials for energy efficiency and thermal comfort in buildings Edited by Matthew R. Hall 15 Handbook of biofuels production: Processes and technology Edited by Rafael Luque, Juan Campelo and James Clark 16 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 2: Carbon dioxide (CO2) storage and utilisation Edited by M. Mercedes Maroto-Valer 17 Oxy-fuel combustion for fossil-fuel power plants: Developments and applications for advanced CO2 capture Edited by Ligang Zheng


Preface

These are exciting times for the power supply industry! The world of power plant design is faced with a wide range of challenges and opportunities in response to serious concerns about climate change and energy security as we begin to exhaust the world’s cheapest sources of fossil fuels. Developed countries are replacing ageing fleets of power stations with new plants designed to meet present-day expectations. Those expectations include huge reductions in carbon dioxide (CO2) emissions, continuous improvement in performance with respect to other emissions, and ever-increasing demands for higher energy efficiency. Developing countries are experiencing rapid population growth and ever-increasing expectations of affordable electricity in support of higher standards of living. There is a growing acceptance that global CO2 emissions need to be reduced by 60% by 2050, with developed countries aiming for a higher reduction figure of 80% by that date. Uncertainty about the approach to incentivising investment in relevant technologies combined with a recent international financial crisis have led to projected energy gaps that are starting to cause serious concern. Interruptions to cross-border gas supplies have heightened that concern and caused people to consider afresh their views on national energy security. Much attention has been paid to the development programme for renewable energy, with various roadmaps being developed to chart expected progress of different technologies in different countries over time. As these plans develop and parallel plans for nuclear power are deployed around the world, countries look at their forecast energy gaps and try to figure out what role can be played by fossil fuel plants as part of the energy mix in balancing conflicting demands for low-cost, low-carbon electricity that is secure and flexible. This requires a good understanding of the current state of the art in power plants and their major components. This book sets out to provide that overview. The book is divided into three parts for ease of reference. Part I looks at complete power plants and explores developments in gas-fired and coal-fired


xviii

Preface

designs in pursuit of high-efficiency, flexible operation, including various combined-cycle configurations. Part II looks at major equipment developments that are relevant to a range of power plant configurations in pursuit of tighter control, general reductions in emissions and affordable capture of CO2. Part III looks at improving the envelope within which fossil fuel power plants operate by introducing increased levels of fuel flexibility and more cost-effective ways of reducing CO2 emissions and storage costs. The book opens with Fadok’s chapter on gas turbine plants, addressing developments aimed at enabling high-temperature operation for higher energy efficiency, enabling plants to run at variable generation rates (which becomes increasingly important as more renewable electricity comes into the mix), and coping with synthetic gaseous fuels (often derived from coal and rich in hydrogen). The concept of a combined-cycle plant for improved energy efficiency is introduced by Rao, including a useful exposition of the advantages and limitations of gas-fired combined-cycle plants. Zhu and Frey introduce coal through the integrated gasification combined-cycle (IGCC) plant, looking at configurations with and without CO2 capture. Technologies introduced in this chapter for CO2 capture and for control of various other emissions are addressed more fully later in the book in dedicated chapters. This leads into a chapter by Dooley and Svoboda on improving the steam/water cycle in power plants to guard against corrosion and other damage, and the challenge of applying current chemistries to the hightemperature, high-pressure plants that are now being considered. Part II opens with two chapters on gas separation membranes: one by Doong where the emphasis is on separating out the hydrogen and the other by Basile where the emphasis is on separating out the CO2. These chapters distinguish between technologies that are ready for commercial deployment on power plants and technologies that are still under development. Chapters by Miller and Miller then examine technologies for controlling emissions of SOx, NOx, mercury, dust and particulates, providing a combination of practical design guidelines for well-developed technologies alongside some insights into expected future developments. The direction of travel for power plant design in a world of tight emissions control, flexible operation and high reliability includes tight control – and therefore reliable measurement – at every point in the process. Yu et al. provide forward-looking insights into the intelligent use of multiple sensors in achieving tight control in advanced combustors, while Yan also includes some developments for the difficult solids-handling sections of a coal-fired power plant. Part III starts by exploring ways of broadening the feedstock supply base. Dlouhy´ provides a general overview of techniques for low-rank coal upgrading that are not commonly used. Rosendahl takes a different


Preface

xix

approach by exploring a range of biomass materials (both specially grown and waste) and ways in which they can be pre-processed to enable their use in displacing all or part of the feedstock for a thermal power plant, reducing the carbon footprint. Green introduces the concept of underground gasification of coal as a means of harnessing the unmineable coal resources that significantly exceed the figures usually quoted for bankable coal reserves, along with the option of linking it to CO2 capture and storage. This leads into McPherson’s chapter on geological storage of CO2, which explains the often-misunderstood science behind the subject and explores the issues that need to be addressed. The book concludes with Chiesa’s chapter on production of a highly flexible fuel – synthesis gas or syngas – by reforming or gasifying fossil fuels. Here the emphasis is on using the syngas (or hydrogen derived from it) for decentralised power generation, which opens up an opportunity for using rejected heat in a combined heat and power configuration. A common theme across the book is technology development to improve energy efficiency, increase reliability, reduce generation cost and enhance ability to operate flexibly within grids that are absorbing increasing levels of renewable electricity. Another common theme is the range of approaches being pursued to reduce the carbon footprint associated with power generation from fossil fuels while taking account of other regulatory pressures. There are, of course, tensions between these various requirements, leading to new thinking in the realms of materials, mechanical, electrical and instrument engineering. This book is aimed at industry practitioners and academic researchers, and contains material from a blend of the two. The aim throughout is to provide a well-referenced appraisal of the state of the art with guidance on where to find further detail and some pointers to likely areas of future development. I hope you find it both informative and inspiring. Professor Dermot J Roddy Newcastle University UK


Part I Advanced power plant materials and design


1 Advanced gas turbine materials, design and technology J . F A D O K , Siemens Energy Inc., USA

Abstract: This chapter will discuss the technologies and material used in modern industrial gas turbines. Rapid evolution of the gas turbine since its first application to wartime aircraft engines has been made possible through the deployment of advanced materials and technologies. The background of these advancements, their use in the gas turbine, and the drivers for new technologies to achieve higher temperatures and efficiencies will be the main focus. Furthermore, the technologies needed for advanced hydrogenfuelled gas turbines will be considered. Key words: gas turbine, advanced materials, turbine, combustion, compressor, IGCC, NGCC, thermal barrier coating, single crystal, hydrogen, Brayton cycle, CO2 capture, gamma prime phase.

1.1

Introduction

The industrial gas turbine is a key element to meeting the world energy demands today and in the future. The flexibility of this technology facilitates deployment in simple cycle peaking applications as well as combined cycle applications. Evolution from the first industrial gas turbines in the 1940s of about 19% thermal efficiency to today’s combined cycle plants at 60% efficiency has been enabled by advancements in materials, design and technology. This chapter will discuss the background of these advancements, their use in the gas turbine, the drivers for new technologies to achieve higher temperatures and efficiencies, and technologies needed for advanced hydrogen-fuelled gas turbines. In only 50 years, industrial gas turbines have evolved from the early jet engines for airplanes used in the Second World War to one of the most widely deployed power generation technologies in the world today. Early 3 © Woodhead Publishing Limited, 2010

4


applications to power generation were direct adaptations of the jet engine, but, as industrial use increased, especially in combined cycle systems, technologies necessary to advance land-based gas turbines were developed. The first industrial gas turbines went into service in the early 1950s for application in power generation, transportation and mechanical drives. The 1960s saw the development of the combined cycle power plants. By thermodynamically coupling the gas turbine Brayton cycle to the Rankine cycle, an efficiency of 39% was already possible compared to about 30% simple cycle efficiency available at that time (Scalzo and Bannister, 1994). Figure 1.1 shows schematic representations of a simple cycle and a combined cycle gas turbine power plant configuration. In the schematic diagram for a simple cycle, the conditions for

1.1 Schematic representation of a gas turbine in (a) simple cycle configuration and (b) combined cycle configuration.


Advanced gas turbine materials, design and technology

5

Table 1.1 Key differences in requirements for aero engines and heavy industrial gas turbines Parameter

Aeroengine

IGT

Weight Operating time (hours) – steady state – peak temperature Cyclic duty Environment Size

Very important 25 000 < 1000

Not significant > 100 000 > 100 000

Severe Non-corrosive Small

Severe Corrosive Large

temperature Tn and pressure Pn are noted at key thermodynamic points in the gas turbine, where n represents the following: 1. 2. 3. 4.

compressor inlet compressor discharge turbine inlet turbine exhaust.

Despite their common heritage, the aero and heavy industrial gas turbines have significant differences in design and technology. Table 1.1 shows the most notable differences between these technologies. Owing to the weight constraints the most obvious physical differences will be found in the rotor and casing constructions, but other differences are also notable, particularly in the combustor and turbine sections. The key driver for power generation technology is cost of electricity (COE) and the driver for aircraft engines is specific fuel consumption (SFC). Both parameters are driven by efficiency and lead to higher pressures and temperatures, which challenge the gas turbine designer. While the focus of this chapter is heavy industrial gas turbines, frequent reference to the aircraft industry is made to highlight the synergy between these industries. When evaluating the available power generation technologies, COE is levelized over a specified operating period, usually 20 years. This gives the levelized cost of electricity (LCOE) on a per annum basis, and can be expressed as LCOE ¼ fuel cost þ capital cost þ variable maintenance cost þ fixed maintenance cost ½1:1 Figure 1.2 shows the LCOE breakdown for a modern gas turbine combined cycle power plant. It can be seen that the major portion of the LCOE is fuel cost, while capital cost makes up most of the remainder.


6


1.2 LOCE for a natural gas combined cycle (NGCC) power plant (source of data US Department of Energy (NETL, 2007)).

With the main contribution to LCOE being fuel cost, natural gas-fired combined cycles must achieve the highest possible cycle efficiency. Over the past decades this increase has been significant, as can be seen in Fig. 1.3. A similar trend for firing temperature (temperature entering the turbine, T3) and pressure ratio P2/P1 could also be derived. As you will see, these advancements have been made possible through improvements in materials and technologies. The second most significant contributor to the COE is capital cost, therefore, an evaluation of total life cycle cost, to compare the efficiency benefit versus additional cost of higher grade materials is necessary. The LCOE distribution shown in Fig. 1.2 is a very simplified view of the total actual operating cost for a gas turbine based power plant, and also assumes a base-load duty cycle, presented later. The importance of availability, reliability and degradation should not be under-stated. Parts replacement costs are high, and frequent maintenance drives up operating cost. Forced outages must be avoided and efficiency has to be maintained at a competitive level over extended operating intervals. Upgraded conditions in the gas turbine tend to increase risk, therefore extensive rig testing and highly instrumented prototypes are manufactured and tested to verify analysis predictions prior to full commercial product release and market acceptance. Emissions constraints for natural gas combined cycle (NGCC) plants include strict regulations for nitrogen oxides (NOx) and carbon monoxide (CO). Advanced lean premix combustion systems, constrained by emissions, must be capable of operating with contradicting requirements for high temperature and low NOx emissions. Furthermore, the emission of



7

1.3 Trends in output and efficiency (used with permission from Siemens Energy, Inc.).

greenhouse gases like carbon dioxide (CO2) is an increasing concern in the world today and often influences decisions regarding the deployment of new power generation technology. When comparing fossil fuel technologies, NGCC has the lowest emissions of CO2 (one-half of the emissions compared to a coal-fired steam power plant). However, integrated gasification combined cycle (IGCC) plants fuelled by coal are currently being designed to capture CO2 and produce hydrogen-rich syngas (or synthesis gas), which can be burned in gas turbine engines yielding CO2 emissions almost five times lower than those from a NGCC. The challenges of operating on hydrogen-rich fuels resulting from coal-derived syngas (with CO2 captured) will be discussed in more detail later in this chapter.


8


1.2

Development of materials and coatings for gas turbines and turbine components

An advanced industrial gas turbine engine is shown in Fig. 1.4. From left to right the major components of the gas turbine are the compressor section, combustor section and turbine section. The engine shown drives a generator from the compressor (cold end), and employs a can-annular combustion system, where individual transition pieces convey the hot combustion gases to the inlet of the turbine. It is a single-shaft (rotor) engine that operates at 3600 r/min (60 Hz) and is optimized for combined cycle application. A (50 Hz) system operates at 3000 r/min and is approximately 1.2 times the size. The casings are designed with a horizontal split line and multiple vertical joints for maintenance of the individual sections of the engine. The materials for the major components of the gas turbine are subjected to differing operating conditions and criteria, both of which influence material selection.

1.4 Advanced SGT6-6000G industrial gas turbine (used with permission from Siemens Energy, Inc.).



9

1.2.1 Compressor Blades and vanes of large industrial gas turbines are made primarily from hardenable stainless steels (martensitic or precipitation hardenable). Examples are 17-4 and AISI 616 (422) SS. These materials are suitable for the size and temperatures seen in large industrial engines. For single-shaft gas turbine engines, the size of the first stage blade is limited by the centrifugal stress at the running speed. This in turn limits the possible flow rate as it defines the annulus size of the compressor inlet. The length of the blade can be increased significantly when a stronger and/or lower density material is introduced, provided the attachment to the rotor is suitable. In areo engines, with large bypass fan blades, composites and fabricated air foils are being used, along with titanium (Ti) alloys, which have much lower density than low-chromium (Cr) steels. The lower density blades also reduce the pull on the rotor disc and attachment, which will be discussed later in this chapter. Owing to the much higher cost of titanium when compared to stainless steels, Ti blades are not common in heavy-duty industrial turbines. Another factor that affects material selection is the pressure ratio, because the compressor discharge temperature is related to pressure ratio. For a compressor using air as a working fluid (γ=1.4) the relationship is approximated by T2 T1 ¼

T1 ½ðPRÞ0:286 1 Zc ´

½1:2

where ηć is the isentropic efficiency and T2 is the compressor discharge temperature from Fig. 1.1. At high pressure ratios, the temperatures can exceed the capability of stainless steels and require the use of Ni (nickel)based alloys, such as Alloy 625 or Alloy 718. Aero engines operating at pressure ratios above 40:1 commonly use these types of materials. Large industrial gas turbines which are optimized for combined cycle application typically operate in a range of 18:1 to 20:1 within the temperature capability of stainless steels. Some manufacturers offer even higher pressure ratio in applications with reheat cycles and closed-loop steam cooling of the turbine. The use of Ni alloys in the compressor has a direct impact on cost not only for the airfoil materials, but also for the rotor and casings. To avoid higher temperatures, and more importantly to achieve high simple cycle efficiency, compressors with inter-cooling can be employed. For combined cycle applications, where heat is recovered from the exhaust gas of the gas turbine, inter-cooling is not currently used because the low-grade heat rejected by the inter-cooler cannot be recovered efficiently in the cycle. Further, inter-cooling lowers the exhaust gas temperature, so there is a net reduction in combined cycle efficiency.


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Coatings are used in the compressor section for two primary functions: to decrease airfoil surface roughness, and blade and vane tip operating clearances. Coatings on compressor airfoils are used to reduce friction losses and provide some erosion protection against particle ingestion. This is a low-cost method for gaining aerodynamic efficiency, and the coatings can be reapplied during a repair interval. Abradable and abrasive coatings, particularly in the rear section of the compressor, are used to manage tip clearances. In the case of abradable coatings applied to the casing, the compressor blade tips cut into the coating, thereby allowing the operating clearances to be minimized. Variations in assembly alignment, distortion of cases and transient excursions can be accommodated with this type of coating. Similarly, abrasive coatings applied to the rotor can accommodate these variations, as the tips of the stationary vanes are cut by the rotating disc. Both systems are widely used in aircraft engines and industrial gas turbines.

1.2.2 Combustion system The two major components of the combustion systems are the combustor and the transition and these components see the highest temperatures in the gas turbine. In today’s advanced industrial engines, this temperature is above 15508C and in the next generation engines could exceed 17008C. Conversely, since no work is extracted in the combustion system, the mechanical loading on these parts (due to pressure) is low. In addition to the extreme temperature, combustor components are subjected to highfrequency, low-amplitude pressure oscillations, which can lead to high cyclic stress. Acoustic resonance and unsteady heat release (referred to as combustor dynamics) is the source of these pressure oscillations. To combat this loading, the structure could be stiffened, but additional stiffness tends to generate higher transient thermal stress, which can lead to low cycle fatigue. In Fig. 1.4 the mid-section of the engine contains the combustor and transition pieces. The hot sections of the combustor are thin-walled components that can be formed from sheet stock and welded. For advanced combustors, internal cooling passages are manufactured into a layered structure, which can be made prior to forming the final shape. This feature enables the designer to minimize the amount of cooling air consumption, or use steam to cool the components, as in the SGT6-6000G transitions seen in Fig. 1.4. Although the pressure loading is relatively low, creep remains a concern, mainly due to high temperature, but also in areas where pressure is acting on large surfaces with little or no curvature. Materials for combustors and transitions must be easily formed and welded, exhibit resistance to high-temperature oxidation, have good compatibility with thermal barrier coatings (TBCs) and have excellent



11

high-cycle and low-cycle fatigue strength. In the presence of combustor dynamics, wear between mating parts must also be considered. Material for the combustor liner and transition piece is typically Ni-based alloy wrought sheet, such as Alloy X, Alloy 617 and Alloy 230. These alloys also contain a high Cr content, which improves oxidation resistance. These alloys have stable, but relatively low yield strength (compared to turbine superalloys) to temperatures over 8008C, high ductility for forming and good fatigue capability in both low-cycle and high-cycle regimes. The designer can trade material capability and cost of the various available alloys to suit the specific application or area of concern, but in general, the aforementioned materials have good formability, weldability and coating compatibility. For advanced transitions with steam cooling, the compatibility with this working fluid at high temperature is another parameter for consideration. Coatings are applied to combustion systems components to provide an insulation barrier from the hot gas stream and to control wear between mating parts. Thermal barrier coatings, described further in the turbine section, have enabled significant increases in operating temperature. The internal surfaces of the combustors and transitions are coated with a TBC and cooled either by convective cooling through internal channels in the liner, by allowing the cooling air to penetrate the liner through cooling holes that eject into the flow path, or by closed-loop steam cooling. As mentioned earlier, wear between mating components is a concern and gas turbine manufacturers have conducted extensive tests of various material combinations and loading scenarios to quantify the wear characteristics of suitable material combinations. Coatings can also be applied at mating surfaces to protect the base material. Commercially available chromium carbide coatings or T-800 can be applied to the mating surfaces during manufacturing, and reapplied during a repair cycle.

1.2.3 Turbine The turbine section is subjected to high temperature, aerodynamic and mechanical loading. While the bulk average temperature entering the turbine is lower than the combustor temperature due to the addition of cooling air or heat extraction from steam cooling, the stage 1 vane can be subjected to very high local temperature. The rotating blade shown in Fig. 1.5 is designed with a combination of convective cooling augmented by turbulators in the cooling channels, and film cooling ejected at the leading edge, the trailing edge and the suction side (low-pressure side) of the airfoil. Figure 1.6 shows a historical perspective of turbine airfoil technology and material development over the past 40 years. The step changes in gas temperature with the introduction of cooling technologies and the application of TBCs are notable. Betteridge and Shaw (1987) offer a more


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1.5 Cross-section of a cooled rotating turbine blade (used with permission from Siemens Energy, Inc.).

detailed perspective of the superalloy developments, and Scalzo and Bannister (1994) describe the historical advancements in cooling technology for industrial gas turbines in the United States. The turbine and combustion system are able to operate at temperatures above the incipient melting point of the base metal by using cooling in combination with TBC applied by either plasma spray deposition or electron beam physical vapour deposition (EBPVD). R. L. Jones of the Naval Research Laboratory describes the differences between these processes, in particular, the microstructural differences, which affect the coating performance (Jones, 1996). In both processes a metallic interlayer bond coat is applied between TBC and substrate to (a) provide an oxidation and corrosion resistant layer and (b) provide a compatible material for applying the ceramic coating. The net effect of coating, film cooling and convective cooling can be seen in Fig. 1.7 where the temperature difference between the hot gas path and substrate can reach 6008C. An issue arises when coating is lost from the airfoil surface due to damage or delaminating, commonly referred to as spallation. This exposes the bondcoat and, subsequently, the metallic substrate to local gas path temperature. Coating durability is extremely important for this reason, but if the coating is lost,



13

1.6 A historical trend of turbine materials and technology (used with permission from Siemens Energy, Inc.).

1.7 Through-thickness temperature gradient for a coated substrate.


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the oxidation resistance of the substrate must be adequate to meet part life requirements. In terms of substrate, superalloys with high Cr content exhibit the best corrosion resistance, while superalloys with high aluminium content offer increased oxidation resistance and improved coating compatibility. In nickel-based superalloys, the higher aluminium concentration also promotes the precipitation of a strengthening second phase known as gamma prime (γ0 ). Gamma prime is an inter-metallic compound with an ordered crystal structure and a composition based on Ni3Al. The gamma prime exhibits a yield stress anomaly whereby its strength increases with temperature, and it is this attribute that imparts superalloys with their exceptional hightemperature mechanical properties. Achieving the optimum balance between mechanical properties, environmental resistance and manufacturability is a challenge which attracts significant research and development effort. The metallurgical complexities of Ni-based superalloys are presented by Sims et al. (1987). In Fig. 1.6 it can be seen that the introduction of single crystal superalloys has enabled high operating temperature of the substrate. The net effect of allowing higher substrate temperature is the ability to lower cooling air consumption and therefore raise turbine efficiency. This significant performance improvement can offset the additional cost of single crystal alloys, however, producing large industrial gas turbine components (three times larger than aircraft engine parts) with single crystal is difficult. Seth (2000) summarized these challenges stating ‘When used for large Utility Gas Turbine parts, the result is very low yield due to distortion and cracking of the core, shell rupture, mold-metal reaction and numerous crystal defects’.

1.2.4 Casings The casings of large industrial gas turbines are classified as pressure vessels and the design guidelines are in fact very similar to those of steam turbines. Without a weight constraint, however, the casings of large industrial gas turbines are unlike aircraft engines in both construction and materials. To facilitate servicing of the engine gas path, the casings share a common horizontal bolted joint as well as several vertical joints, allowing individual casing sections to be removed independently. This feature also allows the use of different materials based on the temperature and loading of that section of the engine. The coupling of these joints is accomplished with industrial grade bolting systems and Bickford (2007) provides a good overview of various bolted joints and materials. In general two temperature and material classifications can be derived. For low-temperature classification up to about 4308C, a low-alloy steel material like ASTM A193 GR B16 can be used. This material is common in petrochemical and power



15

applications and the cost is relatively low in comparison to the hightemperature high-performance materials. For operating temperatures above 4308C a 400 series stainless steel or nickel alloy like Alloy 750 or Alloy 718 may be needed to provide necessary strength and resistance to relaxation or creep, but the cost of these materials is significantly higher than that of the low-alloy steel. Furthermore, it is necessary to consider the thermal expansion coefficient difference between the bolting material and the casing material in order to avoid yielding of the flange or bolting during operation.

1.2.5 Rotors A basic trade-off exists when considering rotor materials for advanced hightemperature engines: cost versus cooling air consumption. The lower cost approach and the approach which is commonly used in heavy industrial gas turbines, is forged steel discs either bolted or welded together. Rotor discs are subjected to high stress at the inner diameter, usually corresponding to the lowest temperature, and lower stress at the rim or gas path, which is the region of highest temperature. A significant drop in strength at higher temperature can drive the material selection to Ni-based alloys such as Alloy 706 or Alloy 718 and such a choice is typical in aero engines for the lowest possible weight and highest strength. In heavy industrial gas turbines large discs become challenging to manufacture in these Ni-based materials and the cost associated with the materials can be prohibitive. To address higher temperatures, cooling air can be fed through the rotor to keep the bulk temperature within an allowable range. In gas turbines, however, any air that is used for cooling is a penalty on efficiency and output.

1.3

Higher temperature efficiency operation

This section discusses the challenges of reaching higher temperature and efficiency and the issues facing the gas turbine designer with regard to extending material capabilities, improving aerodynamic efficiency, all while achieving high mechanical integrity. In simple cycle, the gas turbine efficiency is related to pressure ratio by the relationship shown in Fig. 1.8. The difference between the theoretical efficiency and efficiency with losses increases with pressure ratio due to higher loading and inefficiencies in the compressor and turbine airfoils, the increased effect of compressor tip clearances with smaller airfoils (especially in the rear of the compressor), and increasing turbine leakage air due to non-ideal sealing between stationary and rotating parts. The relationship shown is for a constant turbine inlet temperature, selected at 15008C. In combined cycle applications, there exists an optimum engine pressure ratio for a given turbine inlet temperature. For example, for an inlet temperature of 14008C, the optimum


16


1.8

Gas turbine efficiency versus engine pressure ratio.

pressure ratio is about 17:1, whereas an inlet temperature of 15008C would lead to a higher pressure ratio of about 20:1. This results from a balance between the gas turbine power and efficiency, and the steam cycle power. Because of the decreasing exhaust temperature with increasing pressure ratio, there is reduced steam turbine output with increased pressure ratio. The inlet conditions to the heat recovery steam generator (Fig. 1.1) define the amount of steam and conditions at which it can be produced. There is, in theory, an optimum design point where this inverse relationship between the gas turbine efficiency and steam turbine power results in the maximum net combined cycle efficiency. The design point of the gas turbine engine is therefore selected to be near this optimum, but also considers a range of potential advancements to the engine frame such that future growth is possible without complete engine redesign. Figure 1.9 shows the effect of increasing turbine inlet temperature and pressure ratio on combined cycle plant efficiency. An engine with reheat and/or inter-cooling will produce differing results. Also, there are limitations to how high the exhaust temperature can be increased. Today’s high-temperature combined cycle engines operating at greater than 15008C and about 20:1 pressure ratio can reach 60% combined cycle efficiency.



17

1.9 Effect of turbine inlet temperature on combined cycle efficiency (used with Permission from Siemens Energy, Inc.).

1.3.1 Increasing gas turbine pressure ratio Increasing pressure ratio and increased stage loading capability in the compressor have driven technology and materials advancements to produce high-efficiency gas turbine systems. A trend of decreasing isentropic compressor efficiency is seen when increasing pressure ratio (at constant polytropic efficiency) (Saravanamuttoo et al., 2001, p. 61). To address this, high-efficiency airfoils have been developed to incorporate advanced threedimensional aerodynamic features mostly adapted from high-pressure-ratio aero engines, where pressure ratios of over 40:1 are successfully deployed. At these high pressure ratios, the leakage of air between rotating and stationary components is more severe. This is more difficult to manage in large industrial gas turbines compared to aero engines because of the scale, where small gaps result in large areas due to large diameters. Also, the large casings and rotors of industrial gas turbines have much slower thermal response compared to the gas path components and often result in minimum clearance conditions for seals and blade tips being limited by transient operation (start up, shut down, etc.). Significant clearance improvements have been enabled by the use of state of the art transient thermal mechanical analysis calibrated to engine measurements, which are capable of accurately calculating the transient interactions between components, thereby allowing for optimization of engine clearances.


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1.3.2 Turbine design for high inlet temperature The significant increases in turbine temperatures over the past two decades have been enabled primarily by advancements in coatings, film cooling and materials capability. The two main parameters which influence turbine airfoil design, particularly high-temperature airfoils, are the work extracted by the turbine stage and the Mach number of the flow stream. The work or enthalpy parameter can be plotted against the ratio of axial velocity and tangential velocity (Ca/U) on a single diagram with constant efficiency curves (see Fig. 1.9). Increasing loading at constant flow coefficient will result in lower efficiency and one solution could be to increase the number of stages, thereby reducing the work per stage (Δh), or increase the tangential velocity (U), also referred to as wheel speed. Achieving the desired cycle pressure ratio in the fewest number of stages, however, is a cost benefit for industrial gas turbines, and a necessity to minimize weight in aero engines. Therefore, high-pressure-ratio turbines operate with higher loading, or work extracted, per stage than do lower-pressure-ratio turbines. Industrial turbines, unlike aero engines, are not constrained by size or weight, and can operate with low flow coefficients by allowing large annulus size (Ca is low). Furthermore, high Mach numbers and high velocities lead to increased friction losses and high heat transfer in the turbine stage and high Mach numbers can introduce shock losses. The optimization of loading distribution throughout the turbine becomes a trade-off between airfoil count, cooling air consumption and number of stages, but the following limitations constrain the design: . . .

annulus dimensions constrained by centrifugal stress limits of the blades and rotor discs number of blades limited by attachment design to the rotor the blade length limited by gas bending stress and vibration.

To further complicate the optimization process, the tip clearances and other leakage paths are more critical at high pressure ratio. In particular, if the pressure differential increases across a constant opening or gap, the flow increases and this flow bypasses the stage doing no work. As mentioned earlier, higher work leads to higher heat load on the airfoil. Referring back to Fig. 1.6, the heat transfer coefficient of the hot gas and the gas temperature define the conditions of the gas stream for cooling design. Figure 1.10 shows the turbine cooling system for a modern industrial gas turbine. The supply conditions (compressor extractions) to the turbine are selected to enable safe operation of the gas turbine over a wide range of ambient conditions and part load conditions. The coolant pressure and temperature are defined by the compressor characteristics and the coolant flow is calculated to meet the constraints of the overall system as shown in



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1.10 Cooling circuit for a modern industrial gas turbine (used with permission from Siemens Energy, Inc.).

Fig. 1.7. The ribs or turbulators shown in Fig. 1.5 augment internal heat transfer coefficients to take the heat out of the substrate, while the TBC, having very low conductivity, acts as an insulator to limit the heat flow from the hot gas to the substrate. With the numerous combinations possible, optimization between cooling air consumption and aerodynamic efficiency becomes an iterative process that is facilitated by advanced design tools. The use of state-of-the-art simulation tools coupled with multi-variable analysis processes like ‘design of experiments’ and Monte Carlo allow exploration of a very broad design space and aid in the optimization process. Throughout the design process, the theoretically derived optimum must be concurrently balanced against manufacturing capabilities, constraints and cost to arrive at the best solution.

1.3.3 High-temperature combustion Environmental constraints on the emissions of harmful gases like NOx (NO2, NO) and CO define the envelope of operating temperature for the gas turbine combustor. The most common fuel used in industrial applications is natural gas, however, a wide variety of fuels can be burned in gas turbines including those derived from coal gasification. The relationship of NOx emissions and combustor temperature is shown in Figure 1.11 for premix style, dry low emissions systems. Leonard and Stegmaier (1993) derived a curve for an ideally premixed combustor which is shown by a solid line in the graph. CO emissions become more limiting at part load, as described later in section 1.5, therefore the following discussion focuses mainly on NOx emissions at high temperature. Today’s advanced combustion systems can operate with NOx emissions


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1.11

Relationship of NOx emissions and combustor temperature.

below 10 parts per million (ppm) at F-class temperature (equivalent to 14008C at the turbine inlet) and 15 ppm for G-class (15008C inlet). It can be seen that improved mixing can lower NOx emissions across a wider range of combustor temperatures; however, the challenges associated with this task are multidimensional. Limitations due to combustor flashback and pressure oscillations or dynamics, affect the operability of premix systems at high temperature and lowering emissions at these conditions is the subject of extensive continuing research and development. The efficiency of the gas turbine combined cycle is highly dependent on the inlet temperature to the turbine and the combustor temperature is limited by emissions. Therefore, the difference between the combustor temperature and the turbine inlet temperature should be minimized. Air cooling of the transition piece and combustor liner, in addition to leakages through seals and gaps, will increase this difference. Steam-cooled transitions were first deployed in the late 1990s to maintain high turbine inlet temperature and low NOx emissions (Southall and McQuiggan, 1995). For base-loaded combined cycle plants with few starts, this system provided advantages in power output and emissions. The demand for high-cycling, flexible plants has driven the gas turbine designers to develop air-cooled systems and improved premix combustors, which can simultaneously achieve low emissions and high turbine inlet temperature. Emissions standards vary world-wide and also depend on whether the application is simple cycle or combined cycle. In the USA the



21

Environmental Protection Agency (EPA) develops and enforces standards for emissions. Here, the low emissions standard for combined cycle power plants often necessitates the use of a selective catalytic reduction (SCR) system. NOx removal efficiency can reach 95% in state-of-the-art SCR systems. In combined cycle applications, the exhaust from the gas turbine passes through a heat recovery steam generator (HRSG) which utilizes the gas turbine exhaust energy to produce steam and subsequently generate power in a steam turbine power plant. Figure 1.1 shows the schematic representation of a combined cycle power plant. The temperature of the exhaust gas decreases as it flows through the HRSG and provides suitable conditions (lower temperature) for applying SCR technology. As stated earlier, these systems can achieve about 95% reduction efficiency; therefore, gas turbine emissions for combined cycle gas turbines can be as high as 40 ppm and still achieve 2 ppm emissions from the HRSG stack. This reduction of emissions requires significant amounts of ammonia injection and can lead to ammonia carry-over or slip, which is a harmful emission and can lead to excessive degradation of the HRSG, (EPA, 1997; EPA, 2004).

1.4

Design for hydrogen-rich gases

Integrated gasification combined cycle power plants utilize a gasification process using coal or other feedstock that produces a fuel comprising mainly hydrogen and CO. Gas turbines, which were optimized for operation on natural gas fuel, have been adapted to burn high-hydrogen and other synthetic gaseous fuels. By utilizing a combustor capable of operating on syngas fuels and making minor control changes to gas turbine and associated auxiliary systems, industrial gas turbines have been deployed for IGCC. Table 1.2 shows the fuel properties for three sample fuels – a typical natural gas, a coal-derived synthetic gas (syngas) and a hydrogenrich syngas – alongside pure hydrogen (US DOE, 2004). The hydrogen-rich gas can be the product of ‘shifting’ CO, which is a major portion of a typical syngas composition to CO2. The resulting CO2 in this case is captured and stored to reduce greenhouse gas emissions. Today’s IGCC gas turbines inject nitrogen or steam to control NOx emissions. This process dilutes the fuel, lowers the flame temperature and thereby lowers the emissions of the Table 1.2

Comparison of heating values for syngas and natural gas

Fuel

Approximate heating value LHV (KJ/kg)

Natural gas Syngas (diluted) High-hydrogen ‘shifted’ syngas Pure hydrogen


43 000 5000 7500 120 000

22


combustion system. From the table, it can be seen that the heating value (kJ/ kg) of the diluted syngas fuels is significantly lower than that of natural gas. Therefore, if heat input to the gas turbine is held constant, this affects the fuel mass flow and consequently, the operability of the compressor and combustor. A second observation is the high concentration of hydrogen, especially in the shifted case, which presents a challenge for the combustion system operability and emissions. In addition, a high concentration of H2O in the combusted fuel, and the potential for contaminants in the fuel stream, have direct implications on all of the hot gas path components and materials.

1.4.1 Compressor operability (surge margin) For the same heat input, the fuel flow of diluted syngas is greater by a factor of almost 10 when compared to that of natural gas. For a typical naturalgas-fired turbine, the fuel flow is about 2–3% of the engine air flow while it is almost 20% when utilizing diluted syngas. The difference is enough to cause a noticeable imbalance between the turbine and compressor mass flows, which affects the compressor operating characteristics. Figure 1.12 presents pressure ratio versus the non-dimensional mass flow of an industrial gas turbine compressor. A curve drawn near the inflection points of the speed curves defines the surge line of the compressor, while one operating line established by the turbine is depicted by the dashed line. The difference between the operating line and the surge line is called the surge margin. When a natural gas engine is operated on syngas, the flow through

1.12

Compressor characteristic.



23

the turbine section increases and the turbine acts as a fixed orifice, which causes the pressure ratio to increase. To maintain the same turbine pressure ratio as for the natural gas engine, the flow to the turbine section must be reduced or the geometry of the turbine vane 1 must be modified to open the throat area and allow higher mass flow. There are three primary mechanisms for reducing the flow to the turbine, adjusting the inlet guide vanes, extracting air from the compressor exit and lowering the fuel dilution. Adjusting the inlet guide vanes lowers the compressor mass flow and consequently lowers the flow to the turbine section. Note, during start up and loading of an industrial gas turbine, the inlet guide vanes and firing temperature are used to control the part load power. For a syngas-fired engine, closing the inlet guide vanes at full power results in constant pressure ratio, but lower compressor flow. From Fig. 1.12 it can be seen that this leads to a reduced surge margin. This condition is exacerbated during a hot day, grid under-frequency event as the compressor operates on a lower speed line, because the operating point is shifted to the left on the graph. Modifications to the compressor are possible to gain surge margin, including the addition of stages to the compressor. This approach, however, is a more drastic change to the engine frame and, therefore, it is often more appealing simply to extract air from the gas turbine. Air extracted from the gas turbine can be used to supplement the air used in producing oxygen for an IGCC plant which utilizes a cryogenic air separator. In fact, it is possible to supply all of the necessary air from the gas turbine, and some applications of IGCC have been developed to supply a range of extraction amounts to address the potential issue of compressor surge described earlier. There are cases where no extraction is necessary, and this is highly dependent on the fuel composition, which governs the amount of dilution needed to meet NOx emissions requirements.

1.4.2 High-hydrogen combustion Hydrogen is the most challenging fuel for combustion due to its high flame speed, propensity for flashback and higher dilution requirement for NOx emissions, flame speed and flashback abatement. Figure 1.13 shows the predicted flame speed of various syngas fuels and that of natural gas, where the highest flame speed is found with hydrogen. Combustion systems for IGCC-based gas turbines are currently based on a diffusion flame burner. This combustor has been proven to operate reliably with a variety of synthetic fuels with 15 ppm NOx emissions (Wu et al., 2007). Until the 1990s, diffusion flame burners were also the primary choice for natural gas applications while the dry low NOx (DLN) combustors were being deployed and proven. Like the diffusion combustors burning natural gas, the combustor for IGCC applications requires dilution with nitrogen, steam


24


1.13 Predicted turbulent flame speed for various fuels (used with permission from Siemens Energy, Inc.).

1.14 Correlation of relative NOx with stoichiometric flame temperature (used with permission from Siemens Energy, Inc.).



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or both to achieve acceptable NOx emissions from the gas turbine. The relative NOx emissions are exponentially proportional to the flame temperature, as can been seen in Fig. 1.14. Future developments of combustors for IGCC are targeting premix combustors which can operate at high temperature, with low emissions and require little or no dilution. For example, under sponsorship by the US Department of Energy, research is being conducted to address the challenges of operating a premix style combustor with high hydrogen content in the fuel. Compared to natural gas (over 93% methane), hydrogen has a significantly higher flame speed (Fig. 1.12) and shorter ignition delay time, which can lead to combustor flashback, or flame holding, in addition to the operability limitations due to combustor pressure fluctuations or dynamics.

1.4.3 Turbine design and materials for high hydrogen The combustion products from diluted, hydrogen-rich gas are significantly different from those from natural gas combustion and lead to: . . .

higher heat loads on airfoils higher turbine exhaust temperature material degradation.

The increased heat loads on the airfoils are caused by high gas path heat transfer coefficients due to higher mass flow, as well as the increased moisture content in the fuel. As a result, natural gas turbines adapted for high-hydrogen operation are de-rated to lower turbine inlet temperatures in order to maintain metal temperatures within allowable limits. Referring to Fig. 1.15, the increased axial velocity due to the higher mass flow would also tend to reduce turbine efficiency. In IGCC applications, particularly with high dilution, the measures taken to manage surge margin, namely reducing compressor flow or extracting air from the compressor exit, can help the turbine section. In addition to the heat loads imposed by combustion products, contaminants in the fuel stream can cause deposition and erosion of the turbine materials. In IGCC, the products of coal gasification can include heavy metals, sulphur, potassium, sodium and fly ash entrained in the syngas. Sulphur removal in the plant can reduce the concentrations to about 10 ppm, and even lower levels are achievable but with added cost. Despite extensive clean-up processes, some levels of contaminants will be present in the fuel which enters the gas turbine. Particulate or ash deposition has been experimentally studied at Brigham Young University to measure the effects of various parameters including temperature and particle size. The findings of the study showed that there was a threshold temperature in the range


26


1.15

A turbine enthalpy diagram.

860–9608C where the deposition increased exponentially. Testing under the same programme showed the effect of film cooling was a decreased deposition rate (Crosby et al., 2007). The effect of fuel contaminants is the subject of ongoing research under the sponsorship of the US Department of Energy and in the private sector.

1.5

Design to run at variable generation rates

Gas turbines are a key element in meeting electricity demand during peak periods due to their inherent fast starting and load-following capabilities. Figure 1.16 shows the operating regimes for industrial gas turbines used for power generation. It can be seen that the utility gas turbine can be subjected to a wide range of duty cycles ranging from peaking duty, with frequent starts and stops, through base load operation with a low number of starts. In reality, gas turbine engines are being operated in a combination of these regimes, identified as intermediate duty. An example is the need for additional capacity in the southeast region of the USA in the summer time due to residential and commercial air conditioning. Consequently, the gas turbine design must be capable of high cycling (limited by low cycle fatigue), and extended high-temperature operation (limited by creep). These damage mechanisms are not, however, independent. The combined effects of cyclic and high-temperature operation leads to thermal mechanical fatigue (TMF), a combined creep and fatigue interaction. The Electric Power Research Institute showed a steady decline in gas turbine capacity factor (the ratio of actual operating hours versus available operating hours) of over 38% from 1998 to 2004. Largely driven by natural



27

1.16 Operating regimes based on ISO-3977-2.

gas prices (see Fig. 1.2 for the relative impact on COE), NGCC plants, originally specified as baseload duty, adapted operation to intermediate and even cycling duty. The definition of baseload so far has omitted a very important aspect to the gas turbine engine duty cycle: variable generation rates or load following. Figure 1.17 depicts load following over a 24 hour period. Gas turbine load is modulated to meet the varying demands

1.17 Operating at variable generation rates – an example of load following.


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throughout the day, for example, the low demand for power during the night compared to the high afternoon load in warm climates with airconditioning load. In the case of load following, the gas turbine combined cycle can be remotely governed by a central dispatch controlling multiple generation facilities to manage capacity and demand. Also, in the figure, there is an apparent minimum load to which the gas turbine output can be lowered. As can be seen from the graph, by keeping the combined cycle plant on-line at low loads, the plant can respond very rapidly to changes in demand, which it cannot do if shut down. There are further complications of cycling combined cycle plants, including a rough estimated cost of $10 000– $15 000 per gas turbine start (Parkinson, 2004), and impacts to HRSG and steam turbine components, that must be considered by an operator to determine if it is more economical overall to keep the plant running at low load overnight, maybe at a loss of revenue, versus the cost of a shut down. Environmental constraints, such as NOx and CO emissions, are the limiting factors that define this lower limit of operation, also known as turn down. The inverse relationship of NOx emissions and CO emissions versus combustor temperature is shown in Fig. 1.18. The gas turbine, by design, controls part-load power by closing the compressor inlet guide vanes to reduce flow, which in turn reduces pressure ratio (see Fig. 1.12), and lowers turbine inlet temperature. The combustor temperature is reduced, and the CO emissions increase (exponentially) to the point where the plant permitted limit is reached. In addition to the emissions issue, the turbine

1.18

NOx and CO emissions trends.



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and compressor operating off the design point have lower efficiency and the gas turbine heat rate is worse at part loads. This situation exacerbates the issue of operating at part load overnight. While many combined cycle plants, particularly in the USA, are equipped with SCR systems, this provides abatement primarily for NOx emissions. As such, some power plants have also included a separate catalyst of CO abatement.

1.6

Future trends

The gas turbine will continue to be an important part of the power generation technology mix to serve future energy demands. In a carbon constrained world, the gas turbine technology is a necessary element to provide low emissions, base load and peaking capacity, especially for the widely varying and unpredictable generation from renewable energy technologies. In fact, the National Renewable Energy Laboratories (NREL) shows that an almost equal capacity of peaking and combined cycle gas turbine plants is needed for every gigawatt of renewable energy installed capacity. To meet this demand, and remain environmentally compliant, cycling and high efficiency will be key, while economics are achieved with increased output to reduce capital costs on a $/kW basis. Because the main driver for increased combined cycle efficiency is firing temperature, high-temperature-material systems using minimal cooling in the turbine and combustor are needed. Referring back to Fig. 1.6, it can be seen that a step change in surface temperature capability will facilitate an increase of gas path temperatures beyond 16008C. To meet this challenge, high-temperature, low-conductivity ceramic coatings are being developed by several manufactures. However, operating temperatures are well above the melting point of the substrate and will require the coatings to be highly reliable. Debonding or spallation of coatings would lead to rapid degradation of the metallic substrate, therefore, a next generation of engine health monitoring and on-line diagnostics will be required to identify coating and material distress before a failure occurs. Ceramic matrix composites (CMC) materials are being introduced into industrial gas turbines to offer high-temperature capability with little cooling required. High CMC cost due to producibility problems is currently a major drawback. Collaborative efforts across military and civil aviation as well as power generation industries are necessary to advance the manufacturing readiness level of CMC and reduce the costs. Developments in superalloys for industrial applications will continue to target increased temperature capability, better compatibility with coating systems, and improved oxidation and corrosion resistance. Manufacturers are utilizing elemental additions to today’s superalloys to identify chemistries that will improve these materials.


30


Producing large single crystal castings for turbine blades and vanes is a significant manufacturing challenge and has limited the deployment of these superalloys into heavy industrial gas turbines, again driven by cost and producibility. To address this, modular components are being investigated to allow the use of more expensive materials only in areas where absolutely needed. A turbine vane segment where a single crystal airfoil is coupled with a conventionally cast shroud is one possible combination. While this solves one manufacturing issue, others could arise including the manufacturing of necessary joints between components and precision tolerances that can tend to drive up costs. Through the utilization of high-temperature, high-strength materials solutions, gas turbines can reach gas path operating temperatures of over 17008C. Furthermore, new and novel approaches in sealing and cooling will reduce the consumption of cooling and leakage flow in the hot section of the engine to improve the efficiency further. Advanced aerodynamic flow path optimization will continue to extend the efficiency capability of both compressor and turbine sections. With these improvements a combined cycle efficiency of 65% is within reach. Governments and major original equipment manufacturers (OEMs) are collaborating on research and development in these areas to reach this next level of efficiency for NGCCs and coal-based IGCC with capture. These developments not only seek to reduce fuel consumption, but also to reduce emissions of NOx, CO and CO2. The already low emissions from NGCCs will continue to make them an important technology to meet the future energy demands, the movement towards lower CO2 emissions and the growing renewable energy market.

1.7

Sources of further information

Betteridge, W. and Shaw, S. W. K., ‘Overview development of superalloys’, Material Science and Technology, September 1987, 3. Crosby, J. M., Lewis, S., Bons, J. P., Ai, W., and Fletcher, T. H., ‘Effects of particle size, gas temperature, and metal temperature on high pressure turbine deposition in land based gas turbines from various synfuels’, ASME Turbo Expo 2007, Montreal, Canada, GT2007-27531, 2007. Diakunchak, I., Kiesow, H. J., and McQuiggan, G., ‘The history of the Siemens gas turbine’, ASME Turbo Expo 2008, Berlin, Germany, GT2008-50507, 2008. Erickson, G. L., ‘Superalloy developments for aero and industrial gas turbines,’ Proceedings of ASM 1993 Materials Congress Materials Week ’93, Pittsburgh, Pennsylvannia, 17–21 October 1993. Fuskuizumi, Y., Muyama, A., Shiozaki, S., and Uchida, S., ‘Large frame gas turbines, the leading technology of power generation industries’, Mitsubishi Heavy Industries, Ltd Technical Review, 2004, 41 (5). Stringer, J. and Viswanthan, R., ‘Gas turbine hot-section materials and coatings in



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electric applications’, Proceedings of ASM 1993 Materials Congress Materials Week ’93, Pittsburgh, Pennsylvania, 17–21 October 1993. Seth, B., Superalloys – the utility gas turbine perspective, 2000, Superalloys 2000: 9th international symposium on superalloys (eds T.M. Pollock et al.), TMS US Department of Energy, Gas Turbine Handbook, see http://www.netl.doe.gov/technologies/coalpower/turbines/refshelf/handbook/ TableofContents.html for further information.

1.8

References

Betteridge, W. and Shaw, S. W. K. (1987), ‘Overview development of superalloys, Material Science and Technology, 3, September. Bickford, J. H. (2007), Introduction to the design and behaviour of bolted joints, 4th edn, Vol. 1: Non-Gasketed Joints, Taylor & Francis. Crosby, J. M., Lewis, S., Bons, J. P., Ai, W., and Fletcher, T. A. (2007), ‘Effects of particle size, gas temperature, and metal temperature on high pressure turbine deposition in land based gas turbines from various synfuels’, ASME Turbo Expo 2007, Montreal, Canada, GT2007-27531, 2007. EPA (1997), EPA 420-F-05-015, Environmental fact sheet, see http://www.epa.gov/ oms/regs/nonroad/aviation/aircr-fr.pdf for further information. EPA (2004), National emission standards for hazardous air pollutants for stationary combustion turbines, see http://www.epa.gov/EPA-AIR/2004/March/Day-05/ a4530.htm for further information. Jones, R. L. (1996), Thermal barrier coatings. Mettalurgical and ceramic protective coatings. London, Chapman and Hall. Leonard, G. and Stegmaier, J. (1993), ‘Development of an aeroderivative gas turbine dry low emissions combustion system’, International Gas Turbine and Aero Engine Congress and Exposition, Cincinnati, Ohio. National Energy Technology Laboratory, US Department of Energy (2007), Cost and performance baseline for fossil fuel plants, DOE/NETL-2007/1281, see www.netl.doe.gov for further information. Parkinson, G. (2004), ‘Capacity utilization of combined cycles in the US’, Power Magazine, Nov–Dec. Saravanamuttoo, H., Rogers, G., and Cohen, H. (2001), Gas turbine theory, 5th edn, Prentice Hall. Scalzo, A. J. and Bannister, R. L. (1994), Evolution of heavy duty power generation and industrial combustion turbines in the United States, ASME 94-GT-488. Seth, B. (2000), Superalloys – the utility gas turbine perspective, Superalloys 2000: 9th international symposium on superalloys (eds T. M. Pollock et al.), TMS. Sims, C. T., Stoloff, N. S., and Hegal, W. C. (1987), Superalloys II, WileyInterscience. Southall, L. and McQuiggan, G. (1995), ‘New 200 MW Class 501G combustion turbine’, ASME paper 95-GT-215. US DOE (2004), Quality guidelines for energy system studies, US Department of Energy Office of Systems and Policy Support, see http://www.netl.doe.gov/ publications/others/quality_guidelines/main.html for further information. Wu, J. et al. (2007), Advanced gas turbine combustion system development for high hydrogen fuels, ASME GT2007-28337.


2 Gas-fired combined-cycle power plant design and technology A . D . R A O , University of California, USA

Abstract: A combined cycle consists of combining two power cycles in series to obtain a high overall thermal efficiency, significantly higher than the individual efficiencies of the two cycles making up the combined cycle. In the combined cycle discussed in this chapter, a Brayton cycle or gas turbine is utilized for the topping cycle and a steam Rankine cycle for the bottoming cycle. Combined cycles come in a variety of sizes, depending on the size and number of gas turbines utilized, and may range from less than 10 MW to in excess of 500 MW while using a single gas turbine. In addition to having high thermal efficiencies, outstanding environmental performance, easy start-up and shut-down and low cooling water requirements, combined cycles have significantly lower staffing, capital cost and construction time requirements when compared to boiler based power plants. On the other hand, the clean fuels required by a combined cycle are significantly more expensive when compared to fuels such as coal and biomass that can be directly combusted in a boiler. Included in this chapter are a discussion of types of gas turbines for combined-cycle applications, types of steam cycles in combined-cycle plant, plant design and technology, fuel specifications, control technologies for criteria pollutants as well as for CO2 emissions, and limitations of gas-fired combined-cycle plants. Future trends for improvements in performance and emissions are also discussed. Key words: combined cycle, efficiency, gas turbine, HRSG, steam turbine, topping cycle, bottoming cycle, pre-combustion control, post-combustion control, SCR, Wobbe Index.

2.1

Introduction

A combined cycle consists of combining two power cycles in series to obtain a high overall thermal efficiency, significantly higher than the individual efficiencies of the two cycles making up the combined cycle. Figure 2.1

32 © Woodhead Publishing Limited, 2010

Gas-fired combined-cycle power plant design and technology

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2.1 Efficiency gain of a combined cycle over a simple cycle.

depicts simplified block flow sketches showing the energy flows in a single or ‘simple cycle’ and in a combined cycle. In the case of a simple cycle with a thermal efficiency of 40%, 40 units of electrical energy are produced when 100 units of fuel energy are supplied while 60 units of energy are rejected (primarily through its exhaust gas). In the case of a combined cycle, by installing a second or ‘bottoming’ cycle with a thermal efficiency of 30% in series with the previous cycle of 40% efficiency, it can be seen that an additional 18 units of electrical energy are developed from the energy rejected by the ‘topping’ cycle, resulting in an overall thermal efficiency as high as 58% (neglecting generator, heat and mechanical losses as well as the small change in efficiency of the topping cycle when its exhaust pressure is increased to accommodate the bottoming cycle). In the combined cycle discussed in this chapter, a Brayton cycle or gas turbine is utilized for the topping cycle and a steam Rankine cycle for the bottoming cycle. Combined cycles come in a variety of sizes depending on the size and number of gas turbines utilized. Combined cycle sizes may range from less than 10 MW to in excess of 500 MW when using a single General Electric H class 50 cycle gas turbine.

2.1.1 Types of gas turbines for combined-cycle applications The optimum pressure ratio for a gas turbine in combined-cycle applications is much lower than that required for peak thermal efficiency of a simplecycle gas turbine. Most combined-cycle applications employ gas turbines with the basic Brayton cycle configuration, i.e. adiabatic compression and expansion, and near constant pressure heat addition in the combustor (Cengel and Boles, 1998). A number of variations are possible to the


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2.2

Gas turbine with and without reheat.

Brayton cycle and the ones most useful in combined-cycle applications are addition of reheat during expansion and intercooling during compression while maintaining very high pressure ratios. Reheat can be used to either increase the cycle efficiency for a given turbine inlet temperature or to achieve a target thermal efficiency while lowering the required turbine inlet temperature. Gas turbines with and without reheat are is depicted in Fig. 2.2 along with the enthalpy (h) and temperature (T) versus entropy (s) diagrams for the case where cycle efficiency is held the same while the turbine inlet temperature is lowered for the reheat cycle. In these diagrams, the heat added in the combustor of the gas turbine without reheat is represented by q while qHP and qRH represent the heat added to the high-pressure (HP) and the reheat combustors of the reheat cycle. WC and WT represent the work associated with the compressor and the turbine for the case without reheat, while WLPC, WHPC, WLPT and WHPT represent the work associated with the low-pressure (LP) compressor, the HP compressor, the LP turbine and the HP turbine respectively for the case with reheat. Refer to Cengel and Boles (1998) for more details on the thermodynamic characteristics of such power cycles.

2.1.2 Types of steam cycles in combined-cycle plant Steam generated in gas turbine exhaust is superheated before it is supplied to a steam turbine for expansion in order to increase the thermal efficiency.



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Reheating can also be advantageously used in the steam cycle when exhaust temperature of the gas turbine is high, typically in excess of 5508C. Further improvements in efficiency may be obtained by producing steam at different pressures; a large state-of-the-art combined cycle consists of generating steam at three different pressures in addition to superheating and reheating the steam. Figure 2.3 depicts the temperature (T) versus entropy (s) diagrams for single and dual pressure non-reheat ideal Rankine steam cycles. Refer to Cengel and Boles (1998) for a discussion of the thermodynamic characteristics of various types of Rankine cycles. As can be seen, the amount of heat recovered from gas turbine exhaust and consequently work produced is limited by the ‘pinch’ temperature (typically 5–108C depending on value of energy recovered) when steam at a single pressure is generated. By lowering its pressure, more steam may be generated but the efficiency of converting the recovered heat to work is reduced. An optimum pressure exists for a given gas turbine exhaust temperature that maximizes the efficiency. By inclusion of a second lowerpressure steam generator, more heat may be recovered and consequently more work may be produced. A single steam turbine serves both highpressure steam and lower-pressure steam, the lower-pressure steam after superheating being introduced into the steam turbine at the appropriate stage. In the idealized examples depicted in Fig. 2.3, water entering the evaporator is at its saturation temperature. In practice, however, the economizer is designed to heat up water to a temperature typically below its saturation temperature by 5–108C (‘approach temperature’) at the design point, this is to avoid sudden phase change occurring across a level control valve located just upstream of the steam drum, or to avoid steaming within the economizer, especially during part-load operation and start-up as this approach temperature decreases.

2.3 Single and dual pressure ideal steam cycles with zero approach temperature.


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2.2

Plant design and technology

2.2.1 Fuel specifications, limits and variability In addition to natural gas, there is a wide variety of gaseous fuels that can be fired in a gas turbine, such as liquefied natural gas (LNG) after vaporization, gasification derived syngas (or synthesis gas), blast furnace gas, refinery waste gas (Rao et al., 1996), landfill gas and gas from anaerobic sewage treatment plants. Composition of these gases as well as that of natural gas can vary significantly. In order to protect the gas turbine and to be able to burn these fuels efficiently, allowable ranges in composition and contaminants are defined by the original equipment manufacturers for each gas turbine model. Acceptable ranges are also defined for temperature, heating value and a modified Wobbe Index (MWI). MWI is calculated from the volumetric lower heating value (LHV) of the fuel gas, its specific gravity relative to air (SG) and its absolute temperature (T) by equation [2.1] pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi MWI ¼ LHV= ðSGÞðTÞ ½2:1 This index is a relative measure of energy entering the combustor for a fixed nozzle pressure drop. Typical allowable variations in this index are ±5%. An issue associated with utilizing a fuel with a heating value that is much lower than what a gas turbine is designed for is that the gas turbine compressor pressure ratio can increase due to a significantly larger mass (associated with the fuel) flowing through the turbine. This can cause compressor surge and damage. Possible solutions could be to close inlet guide vanes to limit the amount of air entering the engine and/or to extract air from compressor discharge if there is use for such pressurized air and if the engine can be modified for this capability. Modifications to the fuel delivery system, including control valve and combustor to burn the fuel efficiently and limit formation of pollutants, may also be required. Fuels with a LHV, as low as approximately 4 MJ/nm3, are acceptable for some gas turbine models after required modifications are made. If H2 content of a fuel gas is very high, pre-ignition and flashback can be issues if a pre-mixed combustor designed to limit NOx formation is utilized. Although typically not present in most fuel gas streams, upper limits also exist for O2 content to avoid pre-ignition and flashback. Preheating fuel using heat from the bottoming cycle can increase overall combined-cycle efficiency while the upper limit is set by design capabilities of the fuel delivery system, including materials used in the fuel control valve, as well as considerations of preignition and flashback when a pre-mixed combustor is utilized. Lower limit for fuel temperature is typically set by the need to keep fuel gas safely above its dew point and avoid formation of methane (CH4) and CO2 hydrates.



37

Fuel components such as moisture, as well as higher hydrocarbons, typically set the dew point. Joule–Thompson cooling across any pressure let-down valve should be taken into consideration. Natural gas as well as LNG are generally free of contaminants that can cause corrosion and/or erosion in a gas turbine but the other fuels can contain contaminants. For example, landfill gas, as well as gas from anaerobic sewage treatment plants, can contain siloxanes which can leave silica deposits on turbine blades. An activated carbon bed located upstream of the gas turbine can remove these compounds by adsorption. Stringent limits are specified for lead, vanadium, calcium, magnesium, total alkalis (sodium and potassium), sulfur compounds, as well as particulate loading by size.

2.2.2 Typical plant process description Figure 2.4 depicts a steam-cooled gas turbine combined cycle (Smith, 2004a) with a triple pressure reheat steam cycle (most gas turbines are air cooled, however, the cooling air being provided by the gas turbine compressor). Ambient air is drawn into the gas turbine air compressor via a filter to remove air-borne particulates, especially those that are larger than 10 microns. Fuel and compressed air are mixed and combusted. Hot gas turbine exhaust flows through a heat recovery steam generator (HRSG). Demineralized make-up boiler feed water (BFW) is sprayed directly into the surface condenser which condenses steam leaving the LP section of a steam turbine at a vacuum. This negative operating pressure of the condenser is set by the temperature of the cooling medium used in the surface condenser. In the case of cooling water supplied by wet cooling towers operating in ambient conditions of 158C and 60% relative humidity, the corresponding operating pressure is typically 4.4 kPa while maintaining a reasonable temperature rise for the cooling water and a reasonable ‘hot-end’ temperature difference between the condensing steam and cooling water in the surface condenser. The combined stream of cold vacuum condensate and make-up BFW is drawn from the surface condenser by the vacuum condensate pump and is heated in an economizer within the HRSG and then supplied to an integral de-aerator that also generates LP steam (at about 460 kPa). The de-aerator removes dissolved gases such as O2 and CO2 in the feed water, which can cause corrosion. Chemicals are also injected into the water to scavenge the small amounts of remaining O2. A small amount of steam is vented with the dissolved gases. Excess steam generated in the deaerator after superheating is fed to the LP section of the steam turbine. Superheating in addition to increasing cycle efficiency also avoids condensation of steam into droplets. Intermediate pressure (IP) BFW is extracted from the main BFW pump and flows through the IP economizer in the HRSG. Saturated IP steam generated (at about 2850 kPa) in the HRSG



2.4 Combined cycle with steam-cooled gas turbine and triple pressure reheat steam cycle.

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is combined with steam leaving the HP section of the steam turbine before it is reheated (to about 5708C, depending on the gas turbine exhaust temperature) and fed back to the IP section of the steam turbine. Saturated HP steam generated (at about 17 400 kPa) in the HRSG is superheated (to about 5708C, again depending on the gas turbine exhaust temperature) and fed to the HP section of the steam turbine. The BFW pump supplies water to the attemperators for temperature control of the superheated and reheated steam. In an attemperator, the steam comes into direct contact with water whereby the steam is cooled through the evaporation of the water. Cooling steam required by the gas turbine is provided from the HP steam turbine exhaust. Steam returning from this closed-circuit cooling of the gas turbine is also combined with the IP steam before it is reheated within the HRSG in parallel with the superheater coils. Steam drums of the HRSG are continuously purged to control the amount of build-up of dissolved solids. The continuous blowdown is cascaded from the HP steam drum to the IP steam drum and blowdown from the IP steam drum is routed to a drum where LP steam is recovered. Water discharging from this drum is fed to a second lower-pressure drum and flash steam produced is vented to the atmosphere. As seen from the above plant process description, the function of an HRSG is to recover heat from the exhaust of a gas turbine to generate steam. The principal mode of heat transfer from gas to water or steam in an HRSG is by convection. The tubes through which water or steam flow are finned to enhance heat transfer surface area. Gas turbine exhaust flowing over the tubes is contained in a casing without any refractory lining because of the significantly lower temperatures as compared to a fired boiler. Since the gas is essentially free of particulates, high gas velocities can be maintained to enhance heat transfer further. However, pressure drop across the HRSG is increased as the velocity is increased, while gas turbine output and efficiency are decreased. This inefficiency manifests itself as higher gas inlet temperature to the HRSG and, since only a portion of this heat is converted to work by the steam cycle, a trade-off exists between overall combined-cycle efficiency and HRSG size, and consequently plant cost. Pressure drop for an HRSG with triple pressure reheat steam cycle is typically 28 mm Hg (mercury) while that for a cycle without reheat is slightly lower, typically 24 mm Hg inclusive of stack losses. Catalysts required for reduction of NOx and CO emissions can also be housed within the HRSG casing and the corresponding increase in pressure drop should be accounted for. Steam from the bottoming cycle may be exported in combined heat and power applications. Duct or supplemental firing may be utilized to increase steam production. This consists of combusting fuel gas in duct burners utilizing O2 contained in the gas turbine exhaust flowing through the


40


HRSG. Attention should be given to overall system efficiency and emissions as well as impact on tube metallurgy due to the higher gas temperatures. Duct burners may be installed either upstream of the superheater/reheater coils or more downstream within the HRSG, i.e. after the gas has been cooled down somewhat in order to limit temperature rise when a significant degree of duct firing is required. Tube surface temperatures should always be maintained safely above the acid dew point of the gas to avoid using expensive tube materials such as Teflon1-coated tubes in the lower-temperature sections of the HRSG. Limiting dew point is typically set by H2SO4 (sulfuric acid) which is formed when sulfur present in the fuel is oxidized to SO3 (typically 1–5%) in the gas turbine combustor (Ganapathy, 1989) and combines with water vapour to form H2SO4. This dew point temperature (TDP in K) may be estimated from the partial pressures (in atmospheres) of H2O vapour and SO3 by equation [2.2] (Pierce, 1977) 1000=TDP ¼ 1:7842 þ 0:0269 log PH2 O 0:1029 log PSO3 þ 0:0329 log PH2 O log PSO3

½2:2

Recirculation of heated condensate may be employed to raise tube surface temperature of the condensate heater coil, typically the cold condensate temperature being lower than the acid dew point. In larger combined-cycle plants where steam is generated at high pressures, demineralized make-up water is required for the steam system. A demineralizer consists of mixed-bed ion exchangers, one in operation mode and one in stand-by mode, filled with cation and anion resins, with internal-type regeneration. This system includes facilities for resin-bed regeneration, chemical storage and neutralization basin. There are various ways of rejecting heat from the surface condenser depending on site conditions and economic parameters. For example, cooling towers may be utilized where plenty of fresh water is available for use as make-up to the cooling towers. Mechanical draft cooling towers have the advantage of lower capital cost but higher electrical power requirement when compared to natural draft cooling towers. Once-through cooling may be utilized when the plant is located close to a large body of water. When using brackish or sea water for cooling, appropriate materials for the surface condenser (such as titanium (Ti)) should be selected. Air-cooled surface condensers can also be used for ‘dry’ locations, but plant efficiency is compromised owing to the higher temperature of the cooling medium (air), need for larger temperature approach and correspondingly higher surface condenser operating pressure. Diversion dampers can be provided upstream of the HRSG to bypass gas turbine exhaust directly to the stack, allowing the gas turbine to operate



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when the steam cycle is down. Leakage across this valve is always a concern and such an arrangement is typically avoided; during normal operation the leakage flow is not available for heat recovery, while during maintenance of the steam cycle, leakage of hot gas towards the HRSG is a concern, requiring two dampers in series with a buffer gas maintained in between. Multiple trains of gas turbines (sometimes as many as four gas turbines) with individual HRSGs may be combined with a single steam turbine in which each of the turbomachineries has its own electrical generator. In a ‘single-shaft’ design, the gas turbine, steam turbine and a single generator are all arranged on a common shaft.

2.3

Applicable criteria pollutants control technologies

2.3.1 NOx control Dry low-NOx combustors currently offered for natural gas applications consist of pre-mixing fuel with air and burning it under lean conditions to reduce flame temperature and thus formation of NOx. Values as low as 9 ppm by volume on a dry basis and ‘corrected’ for 15% (by mole) O2 content in the flue gas are guaranteed for some of the engines. Environmental emissions standards are becoming more stringent, however, and values as low as 2 ppm are being required in a number of locations in the USA. To approach such stringent emission requirements, a selective catalytic reduction (SCR) unit is essential at the current time. NH3 (in aqueous form, which is easier to store) is injected upstream of an SCR unit located within the HRSG to react with the NOx to form N2 and H2O. Gas turbine back pressure is increased in order to accommodate pressure drop across the SCR. Pressure drops as low as 4–5 mm Hg are typical and the corresponding impact on overall combined-cycle efficiency is quite small. Optimum location for an SCR unit within an HRSG which uses 3% V2O5 (vanadium pentoxide) as the active material in the catalyst is typically in the 300–4008C temperature zone.

2.3.2 CO and volatile organic compounds control Oxidation catalysts can provide greater than 90% destruction of CO, volatile organic compounds (VOCs), formaldehyde and other toxic compounds. Oxidation catalysts like the SCR unit are housed within an HRSG at an appropriate temperature and are typically formulated with platinum group metals to achieve maximum conversion of the pollutants. Conversion rates increase with temperature and thus it is advantageous to place this catalyst near the HRSG inlet. Typical catalyst life may be 10 years or more of continuous operation. Occasional washing may be required to


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maintain catalytic performance. At the end of the effective life of the catalyst, spent catalyst is typically recycled for the precious metal value. Pressure drops as low as 3 mm Hg are typical and the corresponding impact on overall combined-cycle efficiency is quite small.

2.3.3 NH3 control (selective catalytic reduction (SCR) unit slippage) NH3 slippage through the SCR unit can be a cause for concern from an environmental emissions standpoint in certain locations. Catalysts for NH3 oxidation are under development for installation in the HRSG downstream of the SCR unit to oxidize the NH3 to elemental N2. Pressure drop of this additional catalytic unit is expected to be similar to that of an SCR unit.

2.4

CO2 emissions control technologies

Approximately a third of all the CO2 emissions due to human activity come from fossil fuel-based power plants, with each power plant capable of emitting several million tonnes of CO2 annually. These emissions could be reduced substantially by capturing and storing the CO2. Two basic options are available for CO2 capture in gas turbine combined-cycle plants: (i) precombustion capture, which consists of capture from the fuel before combustion in the gas turbine and (ii) post-combustion capture, which consists of capture from flue gas before it enters the atmosphere. The separated CO2 may then be sequestered geologically or used for enhanced oil or coal bed methane recovery. Compression of the captured CO2 to a pressure in the range of 11–15 MPa is typically required, depending on sequestration method employed and distance between the sequestration site and the power plant.

2.4.1 Pre-combustion control In pre-combustion capture, a fossil fuel such as natural gas is catalytically reformed by the reaction, CH4 + H2O = 3H2 + CO, or partially oxidized to form a syngas consisting primarily of a mixture of H2 and CO. The next step is catalytic shifting of the CO to CO2 by the reaction, CO + H2O = H2 + CO2, followed by heat recovery, syngas cooling and separation of CO2 from the syngas for sequestration utilizing an absorber column and a stripper column, with a suitable solvent circulating between the two columns. About 85–90% of the CO2 may be absorbed into the solution in the absorber. Solvent loaded with the CO2 is regenerated in the stripper using steam, while a high-purity CO2 stream is released. The pressure at



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which the CO2 is released depends on the type of solvent used. Physical solvents such as mixtures of the dimethyl ethers of polyethylene glycol and chemical solvents such as amine solutions are available and their suitability depends on the syngas pressure; physical solvents such as the glycol are more suitable for higher syngas pressures, typically in excess of 4 MPa. Remaining gas (decarbonized syngas) leaving the absorber, which is now mostly H2, is combusted (in gas turbines) with reduced CO2 emissions to the atmosphere (Rao et al., 1999). An advantage of this scheme as compared to post-combustion capture is that the CO2 present in the syngas is available at a high partial pressure, thereby lowering the energy penalty of separating and pressurizing the captured CO2 stream. The high H2 content of decarbonized syngas precludes use of current design pre-mixed gas turbine combustors to limit the formation of NOx, auto-ignition and flash-back being major challenges. Thermal diluent addition is required to the gas in order to reduce NOx generation when utilizing ‘diffusion’-type combustors. Steam may be injected into the gas turbine as thermal diluent, or water vapour may be introduced into the fuel gas by direct contact with hot water in a counter-current column, while recovering low-temperature waste heat. This second method is thermally more efficient when there is a significant amount of low-temperature waste heat available in the plant for the humidification operation. In partial oxidation plants where O2 is utilized to generate syngas, N2 supplied by an elevated pressure air separation unit used to produce the O2 may also be utilized as a thermal diluent. The choice for relative amounts of the two diluents depends on a number of factors such as amount of lowtemperature waste heat available for the humidification operation and amount of excess N2 available from the air separation unit. It should be noted that the specific heat of the triatomic H2O molecule is significantly higher than that of the diatomic N2 molecule on a molar basis and thus relative amounts of diluents required (i.e. H2O vapour versus N2) on a volumetric or molar basis for a given amount of syngas are quite different to achieve similar flame temperatures. Gas turbine pressure ratio increases when firing syngas as it has a much lower calorific value than natural gas. Increase in pressure ratio is dependent upon the amount and nature of diluent added and the degree to which the gas turbine compressor inlet guide vanes are closed. Surge margin available in the compressor could thus constrain the amount of diluent that may be added and the resulting reduction in NOx emissions, in addition to constraints set by the combustor design with respect to achieving stable combustion while limiting CO emissions. Air extraction from the compressor may be utilized in case of the partial oxidation scheme in order to limit the increase in engine pressure ratio, since the extracted air after cool down and heat recovery can be efficiently used in an elevated


44


pressure air separation unit. The quantity of air that may be extracted is constrained by the minimum required to flow through the combustor liner. H2O vapour content of the working fluid flowing through the turbine section will be significantly higher when firing syngas (with H2O vapour diluent added) as compared to that when natural gas is directly fired in the gas turbine. Reduction in turbine firing temperature may be required to limit hot gas path temperatures owing to different aero-heat transfer characteristics and life-spans of thermal barrier coatings, as well as the lifespans of any ceramics that may be utilized in future advanced gas turbines. Additional reduction in firing temperature may be required to accommodate higher cooling air temperatures resulting from increase in the engine pressure ratio. In the case of a steam-cooled gas turbine, however, reduction in firing temperature due to the increase in pressure ratio may be less significant because the cooling steam temperature may be maintained independently of the gas turbine pressure ratio, assuming the LP air-cooled stages of the gas turbine do not become limiting. Thus, the choice of diluent to be utilized, i.e. H2O vapour versus N2 or their relative amounts, should be included in trade-off and optimization studies. Use of diluents alone with the constraints discussed above cannot reduce NOx emissions sufficiently to meet the stringent requirement of 2 ppm (by volume on a dry basis) and an SCR is still required. A previous study (Rao et. al., 1999) has shown catalytic reforming is more efficient than partial oxidation in pre-combustion CO2 capture plants, the heat rate for the partial oxidation option being about 8% higher while utilizing cryogenic air separation for producing O2. Compared to a plant without CO2 capture where natural gas is directly fired in gas turbines, both plant efficiency and cost are significantly compromised with pre-combustion capture of CO2: an increase of more than 30% in heat rate and a more than doubling of the plant cost on a per kW basis may be expected (Rhudy, 2005). High-temperature membranes which are under development for separation of H2 (Roark et al., 2003) should provide some improvement in performance and possibly also cost for the reforming option, while hightemperature ion transport membranes which are under development for air separation (Richards et al., 2001) should provide some improvement in performance and possibly also cost for the partial oxidation option.

2.4.2 Post-combustion control In post-combustion capture, a fuel such as natural gas is first combusted (in gas turbines) and the CO2 formed during the combustion process is separated from the flue gas for sequestration. When air is utilized in the combustion process, CO2 separation may be accomplished utilizing



45

commercially proven amine solvent processes (Chapel et al., 1999). When nearly pure O2 is used in the combustion process (‘oxy-combustion’), the flue gas is essentially a mixture of CO2 and H2O without significant amounts of N2 , making it easier to separate out a relatively pure CO2 stream for sequestration while emitting essentially no CO2 to the atmosphere (Martinez-Frias et al., 2002). Recycle of CO2 and/or steam to the combustor is required to control turbine firing temperature. An air separation unit is required to supply the required O2 for combustion. Amine-based CO2 capture The process includes an absorber column and a stripper column with aqueous mono-ethanolamine (MEA) solution with proprietary additives circulating between the two columns. Flue gas leaving the HRSG, after cooling in a direct contact cooler and pressurization in a blower to overcome pressure drop in the downstream equipment, is supplied to the absorber where it comes into contact with the MEA solution. About 85–90% of the CO2 may be absorbed into the solution. Solvent loaded with the CO2 is regenerated in the stripper using steam, while a high-purity CO2 stream is released near atmospheric pressure. This method of CO2 capture does not impact combined-cycle plant design except for equipment added downstream of the HRSG. Compared to a plant without CO2 capture, where natural gas is directly fired in gas turbines, both overall plant efficiency and cost are again compromised: an increase of more than 20% in heat rate and a more than doubling of the plant cost on a per kW basis (Rhudy, 2005) may be expected. At the present time, this approach for CO2 capture appears to have lower penalties than the other approaches discussed in this chapter. Oxy-combustion In one variant of this cycle being developed by Clean Energy Systems (Martinez-Frias et al., 2002), a clean fuel such as natural gas and O2 provided by an air separation unit are supplied to a combustor (derived from rocket engine technology) operating at a pressure in excess of 10 MPa and a temperature of 540–7608C. The combustor exhaust temperature is controlled by injection of recycled water and, in some cases, steam. Combustion products consisting of approximately 90% H2O vapour, 10% CO2 by volume and a small amount of O2 enter a HP turbine. Exhaust from the HP turbine at a pressure of approximately 1 MPa – after reheating to a temperature in excess of 12408C by combusting additional natural gas with O2 – enters an IP turbine followed by a LP turbine, which exhausts the gases into a condenser at atmospheric or subatmospheric pressure to condense the H2O vapour and separate the CO2. Most of the condensed water after


46


preheating in the turbine exhaust is re-circulated to the HP combustor. Humid CO2 exiting the condenser may be treated in a catalytic combustor if the residual O2 content is excessive. Another variant of the oxycombustion cycle being developed by Graz University of Technology (Sanz et al., 2005) utilizes a single combustor (non-reheat cycle) operating at a more modest pressure of about 4 MPa as compared to Clean Energy System’s HP combustor pressure, while the combustor exhaust temperature is controlled by recycled steam and a compressed mixture of CO2 and H2O vapour.

2.5

Advantages and limitations of gas-fired combinedcycle plants

In addition to having high thermal efficiencies (60% natural gas LHV basis with a current state-of-the-art combined cycle utilizing a steam-cooled ‘H class’ gas turbine at an ambient temperature of 158C), outstanding environmental performance, easy start-up and shut-down and low cooling water requirements, combined cycles have significantly lower staffing, capital cost and construction time requirements when compared to boilerbased power plants. A combined cycle takes approximately one-third of the time it takes to build a pulverized coal plant. On the other hand, the clean fuels required by a combined cycle, such as natural gas, syngas or distillate, are significantly more expensive when compared to fuels such as coal and biomass that can be directly combusted in a boiler. Advantages for a combined cycle include high reliability, smaller plot space requirement and capability for phased construction, i.e. the gas turbine can be installed during the initial phase (when utilizing a non-steam-cooled gas turbine) to generate peak power before the steam cycle is added, at which point the plant can be used for base-loaded power generation. Advanced gas turbines, however, are constructed with ‘exotic’ materials designed to withstand the extreme operating temperatures necessary to achieve the high efficiency. These materials tend to have relatively low tolerance for thermal cycling and so gas turbine manufacturers severely limit the number of starts per year when warranting performance of gas turbines for such peaking service. Combined cycles have been also used for intermediate-load power generation in some cases and again number of starts per year should be limited, not only owing to the gas turbine limitations but also owing to the HRSG limitations: tubes in the high-temperature sections of the HRSG also cannot tolerate too many thermal cycles. Natural gas-fired combined-cycle plants can use distillate fuel oil as backup fuel to address any potential interruption in natural gas supply. However, in recent years this practice has become more uncommon because of additional emissions of sulfur oxides (SO2 and SO3) formed from the



47

sulfur present in fuel oil, as well as possible deactivation of CO oxidation catalyst, and undesirable formation of ammonium salts (ammonium bisulfate, sulfate and bisulfite) by reaction between NH3 slipping through the SCR with SO3. The ammonium salts can deposit in lower-temperature sections of the HRSG and reduce heat transfer through HRSG tubes (requiring frequent washes), as well as giving rise to particulate emissions. It may thus be better to ensure natural gas fuel availability by securing firm gas transportation. Performance of a gas turbine is affected by ambient conditions of temperature, barometric pressure and to a lesser extent humidity. As ambient temperature or humidity increase or barometric pressure decreases (or site elevation increases), the mass flow of air intake to the gas turbine is reduced. This can have a direct impact on performance of a combined cycle. For example, power output can decrease by more than 10% as ambient temperature increases from 158C to 358C, and by approximately 20% as site elevation increases from sea level to 1800 m. Gas turbine efficiency is also reduced as ambient temperature increases, because its compressor power is increased. In a combined cycle, the steam bottoming cycle tends to dampen the effect of ambient temperature, however, and its heat rate increases by approximately 3% as ambient temperature increases from 158C to 358C. The magnitude of this sensitivity, however, depends on gas turbine exhaust temperature and flow rate (corresponding to a certain ambient temperature) selected for optimizing the steam cycle design. Combined-cycle heat rate may actually show a minimum at the design point ambient temperature, its heat rate increasing at lower temperatures. Effect of air humidity on gas turbine performance depends on the gas turbine firing temperature control scheme used, i.e. whether the exhaust temperature is biased by compressor pressure ratio to the approximate firing temperature. Performance of the steam cycle can also be affected by humidity. Higher humidity can reduce power output, because surface condenser operating pressure is increased as cooling water temperature is increased when cooling towers are utilized for plant heat rejection. Decrease in power output has a direct effect on plant capital cost on a per kW basis, while decrease in efficiency affects plant operating cost on a per kW basis. Combined-cycle power output can be reduced initially through reducing gas turbine inlet air flow by closing compressor inlet guide vanes; the corresponding overall combined-cycle efficiency is not reduced by a significant amount. Further reductions in power output require a reduction in gas turbine firing temperature, which has a significant effect on overall plant efficiency. Heat rate can increase by nearly 20% as power demand is decreased by 50% of its rating point. Part load operation of the bottoming steam cycle should take into consideration increase in heat transfer surfaces within the HRSG per unit of heat transferred, and reduction in steam


48


pressures for a floating pressure steam system, which is typically used in combined-cycle applications. For example, steaming in the IP and LP economizers should be avoided, and pipes should be properly sized for the higher steam velocities at the lower pressures (reduction in velocities due to lower mass flow rates having a less pronounced effect). Like all turbomachinery, gas turbines experience loss in performance with time. Part of this performance degradation is recoverable and is typically associated with compressor fouling; this can be partially fixed by water washing or more fully by mechanical cleaning of compressor blades and vanes. Mechanical cleaning requires opening the unit, resulting in a loss in plant capacity factor. Gas turbines also undergo a non-recoverable loss, which is due mostly to increased clearances in turbine and compressor sections as well as to changes in airfoil contours and surface finish. This loss can only be fixed through replacement of affected parts at required inspection intervals.

2.6

Future trends

Some of the technological advances being made or being investigated to improve the basic Brayton cycle include the following, in addition to changes in the basic cycle configuration such as inclusion of reheat combustion and intercooling (which is justified for very high-pressureratio cycles): . . . . . .

firing temperature of 17008C or higher, which would require development and use of advanced materials including advanced thermal barrier coatings and turbine cooling techniques advanced combustor liner materials (combustion air and combustion products being hotter) due to increases in firing temperature high blade metal temperature in the neighbourhood of ~10408C while limiting coolant amount (this would again require the development and use of advanced materials including advanced thermal barrier coatings) pressure gain combustor cavity or trapped vortex combustor high-pressure-ratio compressor (much higher than 30 to take full advantage of higher firing temperature).

Addition of novel bottoming cycles is yet another approach to improving overall combined-cycle performance. Overall cycle efficiencies utilizing advanced technology gas turbines approaching 65% on natural gas on an LHV basis may be expected in the 2020 to 2025 time frame (Dennis, 2008).



49

2.6.1 Gas turbine firing temperature, pressure ratio and intercooling The single most important design parameter that affects gas turbine thermal efficiency is its firing temperature. Thus, increases in firing temperature are required to make substantial increases in thermal efficiency. Current stateof-the-art gas turbines have firing temperatures (rotor inlet temperatures) that are limited to about 14308C. This increase in firing temperature has been made possible by being able to operate turbine components that come into contact with the hot gases at higher temperatures, while at the same time utilizing closed-circuit steam cooling. In a state-of-the-art air-cooled gas turbine with firing temperature close to 13208C, as much as 25% of the compressor air may be used for turbine cooling, which results in a large parasitic load of air compression. In air-cooled gas turbines, as the firing temperature is increased, the demand for cooling air is further increased. Closed-circuit steam cooling of the gas turbine provides an efficient way of increasing the firing temperature without having to use a large amount of cooling air. Furthermore, steam with its very large heat capacity is an excellent coolant. Closed-circuit cooling also minimizes momentum and dilution losses in the turbine while the turbine operates as a partial reheater for the steam cycle. Another major advantage with closed-circuit cooling is that the combustor exit temperature and thus the NOx emissions are reduced for a given firing temperature; the temperature drop between the combustor exit gas and the turbine rotor inlet gas is reduced because the coolant used in the first-stage nozzles of the turbine does not mix with the gases flowing over the stationary vanes. Note that control of NOx emissions at such high firing temperatures becomes a major challenge. The General Electric and Mitsubishi H class gas turbines as well as the Siemens and Mitsubishi G class gas turbines incorporate steam cooling, although the H class turbines include closed-circuit steam cooling for the rotors of the HP stages. A drawback with closed-circuit cooling, however, is the absence of a cooler protective film over the outside surface of the blades, which is possible with open-circuit ‘film cooling’. Some gas turbine designers are taking this film-cooling approach for higher temperature stages of the more advanced engines. Pressure ratio must also be increased in order to take full advantage of higher firing temperature from an overall thermal efficiency standpoint. Higher pressure ratios are also required to limit turbine exhaust temperature and thermal stresses at the roots of the last-stage turbine blades, which tend to be long in gas turbines for large-scale combined-cycle applications and are uncooled. A research study recently completed for the US Department of Energy (Rao et. al., 2008) showed that for an 8% decrease in combinedcycle heat rate, an increase in firing temperature in excess of 3008C was


50


required over an H class gas turbine while the pressure ratio had to be increased from 24 to 50. Advanced materials in both the combustor and the turbine are required to withstand the severe environment created by the higher temperatures. Spray intercooling of such a high-pressure-ratio gas turbine compressor can decrease compressor discharge temperature by more than 1008C without decreasing overall combined-cycle efficiency. Reduction in compressor discharge temperature has beneficial impacts on compressor material costs as well as NOx formation within the combustor.

2.6.2 Reheat gas turbines As pointed out previously, reheating can be used to reduce firing temperature for a given cycle efficiency, but the pressure ratio required for such a cycle tends to be higher than that required for a simple-cycle gas turbine with higher firing temperature to achieve the same thermal efficiency. Reheat gas turbines have been in commercial operation, as offered by Alstom, and these gas turbines can play a role in achieving higher efficiencies in the future, but as firing temperatures are increased to realize even higher efficiencies, compressor pressure ratio may become the limiting technology.

2.6.3 Materials development Taking the firing temperature beyond 14308C poses challenges for the materials in the turbine hot gas path. Conventionally cast nickel-based superalloys are being replaced by directional solidification blades as well as single crystal blades, which provide significant benefits. Single crystal blades have been utilized successfully in advanced turbines but, in addition to this, developments of advanced thermal barrier coatings are being investigated, including extensive use of ceramics. Ceramic coatings provide thermal barrier protection to reduce metal temperatures. These coatings, however, need to be able to withstand an environment containing water vapour at a high partial pressure. Development of ceramic matrix composites for the hot components or sections of the turbine is also under consideration. Ceramic composites employing silicon carbide fibres in a ceramic matrix, such as silicon carbide or alumina, are commercially available, while single crystal oxide fibres are under consideration. Combustor materials for higher firing temperatures that can withstand a combination of creep, pressure loading, high cycle and thermal fatigue are also under investigation.



51

2.6.4 Combustor developments Pressure gain combustor A pressure gain combustor produces an end-state stagnation pressure that is greater than the initial state stagnation pressure. An example of such a system is the constant volume combustion in an ideal spark-ignited engine. Such systems produce a greater available energy in the end state than constant-pressure systems. It has been shown that the heat rate of a simplecycle gas turbine with a pressure ratio of 10 and a turbine inlet temperature of ~12008C can be decreased by more than 10% utilizing such a constantvolume combustion system (Gemmen et al., 1994). Pulse combustion which relies on the inherent unsteadiness of resonant chambers can be utilized as a pressure gain combustor. Research continues at General Electric and at NASA for the development of pressure gain combustors. This technology holds promise for making significant improvements in cycle efficiency as long as the friction losses can be managed. Trapped vortex combustor The trapped vortex combustor (TVC) has potential for numerous operational advantages over current gas turbine engine combustors (Hsu et al., 1995). These include lower weight, lower pollutant emissions, effective flame stabilization, high combustion efficiency, and operation in the leanburn modes of combustion. The TVC concept evolved from studies of flame stabilization and is a departure in combustor design, using swirl cups for flame stabilization. Stability in swirl-stabilized combustors is somewhat limited and blow-out can occur under certain operating conditions. On the other hand, TVC maintains a high degree of flame stability because the vortex trapped in a cavity provides a stable recirculation zone that is protected from the main flow in the combustor. A bluff body dome distributes and mixes the hot products from the cavity with the main air flow. Fuel and air are injected into the cavity in such a manner that a vortex is naturally formed. The combustion process in a TVC may be considered as staged, with two pilot zones and one main zone, the pilot zones being formed by cavities incorporated into the liners of the combustor (Burrus et al., 2001). The cavities operate at low power as rich pilot flame zones resulting in low CO and unburned hydrocarbon emissions, as well as providing good ignition and lean blow-out margins. At higher power conditions of greater than 30% power, the additional fuel is staged from cavities into the main stream while the cavities are operated at substoichiometric conditions. An operating range of greater than 40% relative to conventional combustors has been demonstrated in experiments, with


52


combustion efficiencies greater than 99%. Use of the TVC holds special promise as an alternative option for suppressing NOx emissions in syngas applications where pre-mixed burners may not be employed. Catalytic combustor Lean stable combustion can be obtained by catalytically reacting fuel–air mixtures with a potential for simultaneous reduction in NOx, CO and unburned hydrocarbons (Smith, 2004b). Catalytic combustion also has the potential for improving lean combustion stability and for reducing combustion-related pressure oscillations. This type of combustor can also play a special role in syngas applications to reduce NOx emissions.

2.7


Combined-cycle power plants Boyce M P (2001), Handbook for cogeneration and combined cycle power plants, New York, American Society of Mechanical Engineers. Fuel gas specifications General Electric (2002), Specification for fuel gases for combustion in heavy-duty gas turbines, Power Systems Bulletin GEI 41040G. Advanced combined cycles Bolland O (1991), ‘A comparative evaluation of advanced combined-cycle alternatives’, ASME Journal of Engineering for Gas Turbines and Power, 113, 190–197. Gas turbine materials Hannis J, McColvin G, Small C J and Wells J (2007), Mat UK Energy Materials Review Materials R&D Priorities For Gas Turbine Based Power Generation. Schafrik R and Spragu R (2004), ‘Gas turbine materials’, Advanced Materials and Processes, May, 29–33.

2.8

References

Burrus D L, Johnson A W, Roquemore W M and Shouse D T (2001), ‘Performance assessment of a prototype trapped vortex combustor for gas turbine application’, In Proceedings of the ASME IGTI Turbo-Expo Conference, New Orleans. Cengel Y A and Boles M A (1998), Thermodynamics: an engineering approach, New Jersey, WCB McGraw-Hill. Chapel D G, Mariz C L and Ernest J (1999), ‘Recovery of CO2 from flue gases: commercial trends’, presented at the Canadian Society of Chemical Engineers annual meeting, 4–6 October, Saskatoon, Saskatchewan, Canada. Dennis R A (2008), ‘DOE advanced turbine program ceramic material needs for



53

advanced hydrogen turbines’, presented at US Advanced Ceramics Association Spring Meeting, May, Arlington, VA. Ganapathy V (1989), ‘Cold end corrosion: causes and cures’, Hydrocarbon Processing, 57–59. Gemmen R S, Richards G A and Janus M C (1994), ‘Development of a pressure gain combustor for improved cycle efficiency’, In Proceedings of the ASME Cogen Turbo Power Congress and Exposition. Hsu K Y, Gross L P and Trump D D (1995), ‘Performance of a trapped vortex combustor’, paper no. 95-0810, presented at the AIAA 33rd Aerospace Sciences Meeting and Exhibition, 9–12 January, Reno, Nevada. Martinez-Frias J, Aceves S, Smith J R and Brandt H (2002), ‘Thermodynamic analysis of zero-atmospheric emissions power plan’, presented at the ASME International Conference, November New Orleans, Louisiana. Pierce R R (1977), ‘Estimating acid dewpoints in stack gases’, Chemical Engineering, 11 April, 125–128. Rao A D, Francuz D J and West E (1996), ‘Refinery gas waste heat energy conversion optimization in gas turbines’, In Proceedings of the ASME Joint Power Generation Conference, October, Houston. Rao A D, Francuz D J, Scherffius J and West E (1999), Electricity production and CO2 capture via partial oxidation of natural gas, CRE Group Ltd, report by Fluor Daniel Inc. Rao A D, Francuz D J, Maclay J D, Brouwer J, Verma A, Li M and Samuelsen G S (2008), Systems analyses of advanced brayton cycles for high efficiency zero emission plants, US DOE/NETL report, University of California, Irvine. Rhudy R (2005), Retrofit of CO2 capture to natural gas combined-cycle power plants, prepared by the International Energy Agency Greenhouse Gas Program for EPRI as a technical update. Richards R E, Armstrong P A, Carolan M F, Stein V E, Cutler R A, Gordon J H and Taylor D M (2001), ‘Developments in ITM oxygen technology for integration with advanced power generation systems’, In Proceedings of the 26th International Technical Conference on Coal Utilization and Fuel Processing, March. Roark S E, Machay R and Sammells A F (2003), ‘Hydrogen separation membranes for vision 21 energy plants’, In Proceedings of the 28th International Technical Conference on Coal Utilization and Fuel Systems, March, Clearwater, Florida. Sanz W, Jericha H, Luckel F, Go¨ttlich E and Heitmeir F (2005), ‘A further step towards a Graz cycle power plant for CO2 capture’, In Proceedings of ASME Turbo Expo, 6–9 June, Reno-Tahoe. Smith D (2004a), ‘H system steams on’, Modern Power Systems, February, 17–20. Smith L L (2004b), Ultra low NOx catalytic combustion for IGCC power plants, US DOE topical report by Precision Combustion, Inc.


3 Integrated gasification combined cycle (IGCC) power plant design and technology Y . Z H U , Pacific Northwest National Laboratory, USA; H . C . F R E Y , North Carolina State University, USA

Abstract: The main process areas of integrated gasification combined cycle (IGCC) plants without and with carbon dioxide (CO2) capture are described. Key factors in IGCC plant design are described for major process areas, including gasification, water–gas shift, gas turbine, CO2 capture, and other emissions control technologies. The advantages and limitations of coal IGCC plants are discussed. The main development trends of IGCC technologies are reviewed and summarized. Key words: gasification, combined cycle, gas turbine, water–gas shift (WGS), CO2 capture

3.1

Introduction: types of integrated gasification combined cycle (IGCC) plants

The global share of coal for power generation was 41% in 2005 and could increase to 46% in 2030 (Energy Information Administration, 2008). With coal remaining a key source for electric power generation, further research and development (R&D) of clean coal technology is required because coal combustion represents a significant source of many air pollutants and carbon dioxide (CO2). Integrated gasification combined cycle (IGCC) is a promising technology for clean generation of power and co-production of chemicals from coal and other feedstocks including petroleum coke, biomass, and municipal solid wastes. Potential advantages of IGCC systems over conventional (not ultra super critical) pulverized coal (PC) power generation systems include higher thermal efficiency, lower emissions, and greater fuel flexibility (Ratafia-Brown et al., 2002a; Rezaiyan and Cheremisinoff, 2005). However, IGCC plants are more costly than PC plants when no CO2 capture is required (Klara, 2007). If substantial CO2 54 © Woodhead Publishing Limited, 2010

IGCC power plant design and technology

55

capture is required, IGCC is expected to have significant cost and performance advantages over PC plants (Nexant, 2006; Klara, 2007). IGCC features the conversion of solid or liquid fuels to a synthesis gas (‘syngas’) in a gasification step. The syngas can be used as a fuel for a gas turbine combined cycle for electricity generation or as a feedstock for chemical synthesis (e.g. ammonia and methanol, etc.), or both. Gasification technology has been used for gas, chemical, and liquid oil production for more than a century (Rezaiyan and Cheremisinoff, 2005; Breault, 2008). The Cool Water IGCC demonstration project, which is the first modern IGCC commercial-scale system, began operation in 1984 (Breault, 2008). More recently, several coal-fueled IGCC commercial-scale demonstration projects have been developed and are now in operation, including Wabash River, Polk, ELCOGAS, Nuon Power, Vresova, and Nakoso (Wabash River Energy Ltd, 2000; Tampa Electric, 2002; Ratafia-Brown et al., 2002a; Hannemann et al., 2002, 2003; Luby and Susta, 2007; Ishibashi and Shinada 2008; Higman, 2008). The key characteristics of these commercial plants are given in Table 3.1. Several new coal IGCC power plants are in development and are expected to be in service in the near future. The 1200 MW Nuon Magnum IGCC plant in The Netherlands is scheduled to begin operation in 2011 (de Kler, 2007). A 275 MW IGCC power plant with carbon capture, known as the FutureGen plant, could be the first-of-a-kind IGCC plant that includes CO2 capture, if this project is revived after being cancelled in late 2008 (FutureGen Alliance, 2007). Two configurations of IGCC plants are now described in more detail. These are the IGCC without CO2 capture and the IGCC with CO2 capture.

3.1.1 IGCC without CO2 capture Figure 3.1 depicts a conceptual design of an IGCC system without CO2 capture. In this system, coal or other feedstocks react with a high-purity oxygen or air to produce a syngas rich in carbon monoxide (CO) and hydrogen (H2) (Rezaiyan and Cheremisinoff, 2005). If high-purity oxygen is required, an air separation unit (ASU) is typically used to produce the oxidant. In a typical entrained-flow high-pressure gasifier (see section 3.2.1, subsection on ‘Entrained-flow gasifier’), most minerals in coal ash are melted at high temperature and cooled by water quenching to form a glasslike slag. The sygnas is cooled and sent to a water scrubbing unit to remove particulate matter (PM), ammonia, and other impurities. The syngas is sent to a physical or chemical solvent-based process to remove acid gases, such as hydrogen sulfide (H2S) and carbonyl sulfide (COS), from the syngas. The separated acid gases are further recovered to produce elemental sulfur or sulfuric acid as a by-product. The clean syngas is sent to a gas turbine combined cycle for power generation. A combined cycle consists of a gas



Commercial 1996 to present 250

Status Years Net power output (MWe) Efficiency (%) (HHV basis a) Gasifier type

N2 injection Siemens V94.2

Steam dilution GE 7FA

N2 injection Siemens V94.3

No Claus (sulfur)

MDEA

Ceramic candle filter + wet scrubbing

Oxygen Coal dry feed Convective water tube boiler

Entrained-flow (Prenflo)

41.5

Puertollano, Spain Commercial 1997 to present 300

ELCOGAS

n/a 2 x GE 9E

No n/a

Rectisol

n/a

Oxygen Lignite dry feed n/a

Moving-bed (Lurgi)

n/a

Vresova, Czech Republic Commercial 1996 to present 400

Sokolovska Uhelna Vresova

n/a Mitsubishi M701DA

No n/a

MDEA

Candle filter + wet scrubbing

Air Coal dry feed Syngas cooler

Entrained-flow (Mitsubishi)

40.5

n/a

No Selectox (sulfur)

Amine

Water saturation Steam dilution GE 7E Westinghouse 501

No Claus (sulfur)

Selexol

Entrained-flow Entrained-flow (General Electric) (Conoco-Phillips E-Gas) Oxygen Oxygen Coal Coal slurry feed slurry feed Radiant water Downflow fire tube and tube boiler convective fire tube boiler Wet scrubbing Wet scrubbing

n/a

Cool Water IGCC Dow Chemical /Destec LGTI Project Iwaki City, Japan Daggett, Plaquemine, California Louisiana Demonstration Demonstration Demonstration 2007 to present 1984 to 1989 1987 to 1995 250 120 160

Nakoso

Demonstration IGCC projects

Source: Ratafia-Brown et al. (2002a); Tampa Electric (2002); Wabash River Energy Ltd (2000); Hannemann et al. (2002); Hannemann et al. (2003); Ishibashi and Shinada (2008); Higman (2008); Luby and Susta (2007). a HHV: higher heating value; b MDEA: methyl diethanol amine.

No Sulfuric acid plant (sulfuric acid) N2 injection General Electric (GE) 7FA

No Claus (sulfur)

b

No Claus (sulfur)

Cyclone + ceramic candle filter + wet scrubbing Sulfinol-M

CO2 capture Sulfur recovery (sulfur byproduct) NOx control Gas turbine

Metallic candle filter + wet scrubbing

MDEA

Radiant water tube and convective fire tube boiler Wet scrubbing

Entrained-flow (Shell)

41.4

Buggenum, Netherlands Commercial 1994 to present 253

Nuon Power Buggenum

Oxygen Coal slurry feed Vertical fire tube Water tube boiler boiler

Entrained-flow Entrained-flow (General Electric) (Conoco-Phillips E-Gas) Oxygen Oxygen Coal slurry feed Coal slurry feed

39.7

West Terre Haute, Indiana. Commercial 1995 to present 262

Wabash River Repowering

Acid gas removal MDEA

Particulate removal

Gas cooling

Oxidant Feed

Polk, Florida

Site

35.4

Tampa Electric Polk

Name

Existing coal IGCC projects

Table 3.1 Major existing commercial and demonstration coal integrated gasification combined cycle (IGCC) power plants

57

3.1

Conceptual diagram of IGCC system without CO2 capture.



58


turbine, a heat recovery steam generator (HRSG), and a steam turbine (Brooks, 2000). The gas turbine includes a compressor, a high-pressure combustor, and an expander. The syngas is combusted with compressed air in the combustor at a pressure of 15 bar or higher. The expander recovers rotational energy from the pressurized high-temperature combustor exhaust. The heat from the gas turbine exhaust is recovered in a HRSG to produce high-temperature steam. The HRSG comprises a series of heat exchangers, including a superheater, boilers for various steam pressure levels, and feedwater heaters. The generated steam, usually at two or three pressure levels, is then expanded in a series of steam turbines. Both the gas turbine and steam turbines drive a generator.

3.1.2 IGCC with CO2 capture Although IGCC systems with CO2 capture have not yet been commercially demonstrated, IGCC systems are considered to have advantages in CO2 capture compared to conventional PC plants because of higher operating pressure and higher concentration of CO2 in syngas than in flue gas (Ratafia-Brown et al., 2002b). High-pressure syngas has a much smaller volume flow rate than the atmospheric pressure exhaust gas from a PC plant. A recent study estimates that the total plant cost for an IGCC system with CO2 capture is approximately 15% lower than that of a supercritical PC plant with CO2 capture (Klara, 2007). Compared to IGCC plants without CO2 capture, the major differences of IGCC plants with CO2 capture (see Fig. 3.2) include: (i) a water–gas shift (WGS) reaction process downstream of gas cooling and scrubbing; (ii) a two-stage acid gas removal process with a sulfur removal stage and a CO2 capture stage; (iii) a CO2 drying and compression unit; (iv) a gas turbine modified for firing syngas with high H2 content; and (v) a steam cycle designed to provide extra steam for WGS reaction if required and to provide steam or water for syngas dilution (Maurstad, 2005; Klara, 2007). In this system, raw syngas generated from gasification is cooled, and fine particles in the syngas are removed by water scrubbing. The syngas rich in H2 and CO is sent to a WGS reactor, in which the bulk of CO is converted into CO2 by reaction with steam (Hiller et al., 2006) CO þ H2 O $ CO2 þ H2

½3:1

From the WGS reaction, H2 is produced from steam. Hence, the H2 to CO ratio of the shifted syngas is very high compared to raw syngas from the gasification. The shifted syngas is sent to a two-stage acid gas removal process, in which the first stage removes sulfur compounds, and the second stage removes CO2. High-purity CO2 is separated from the syngas and is ready for compression and sequestration. After acid gas removal, the H2-


59

3.2 Conceptual diagram of IGCC system with CO2 capture.



60


rich syngas is sent to a gas turbine combined cycle. Dilution nitrogen or steam/water injection to the combustor is typically used to control NOx emissions by reducing the peak flame temperature.

3.2

IGCC plant design and main processes technologies

The main processes technologies in an IGCC plant are described. The major types of gasifiers and their features are reviewed. The main differences between IGCC systems with CO2 capture and those without CO2 capture are also described.

3.2.1 Coal gasification Coal gasification converts coal into gaseous components via partial oxidation under elevated pressure and temperature. The oxygen consumption of a gasifier is generally 20–70% of the amount required for complete combustion (Rezaiyan and Cheremisinoff, 2005). In gasification, coal particles are heated and devolatilized to produce a variety of species, including char, oil, tars, and gases. The volatiles and char are gasified in solid–gas phase reactions to generate H2, CO, H2O, and CO2. The volatiles also react with oxygen to produce CO, CO2, H2, and other gaseous products. The slowest reactions in gasification are heterogeneous carbon–gas reactions (Higman and van der Burgt, 2003; Rezaiyan and Cheremisinoff, 2005). In a gasification process, reactions include combustion reactions and gasification reactions. The overall reaction can be represented as (Higman and van der Burgt, 2003) Cn Hm þ n=2 O2 ¼ nCO þ m=2 H2

½3:2

where, for coal, n and m are approximately equal. The combustion reactions involve the oxidation of carbon and hydrogen to CO, CO2, and water (H2O), which provide heat for gasification reactions. The gasification reactions mainly include the Boudouard, methanation, and water gas shift reactions C þ CO2 $ 2CO

½3:3

C þ 2H2 $ CH4

½3:4

C þ H2 O $ CO þ H2

½3:5

Three kinds of gasification technologies are generally applied in IGCC systems, including moving-bed, fluidized-bed, and entrained-flow gasifiers.


IGCC power plant design and technology Table 3.2

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Characteristics of major types of gasification technologies

Gasification type Example

Moving-bed gasifier

Fluidized-bed gasifier

Entrained-flow gasifier

Lurgi, British Gas/ Lurgi (BGL)

Kellogg Rust Westinghouse (KRW), hightemperature Winkler (HTW)

General Electric (GE), ConocoPhillips E-Gas, Shell, or Prenflo

Temperature (oC)

370–650

800–1050

1250–1600

Pressure (bar)

20–25

20–30

20–85

Oxidant Fuel particle size (mm)

Oxygen or air 6–50

Oxygen or air 6–10

Oxygen or air Fine particles, < 0.1

Fuel feed

Dry

Dry

Dry/slurry

Fuel flexibility

Cannot be used to Reactive, nonhandle fine caking fuels particles

Conventional fuel, i.e. coal and oil, and less reactive fuels, e.g. chemical wastes

Syngas

Large amount of methane and heavy hydrocarbon compounds

Some methane and other heavy hydrocarbon compounds

Small amount of methane and no other heavy hydrocarbon compounds

Oxidant consumption

Low

Medium

High

Conversion efficiency

99%

97%

> 98%

Source: Higman and van der Burgt (2003); Rezaiyan and Cheremisinoff (2005); Maurstad (2005); ENEA et al. (2005).

The main features of these three kinds of gasifiers are listed in Table 3.2. The details of each type of gasification technology are briefly described. Entrained-flow gasifier Entrained-flow gasifiers feature co-current flow of feedstock and oxidant. To ensure efficient mixing and high carbon conversion, solid feedstocks must be finely pulverized. Entrained-flow gasifiers typically use oxygen as an oxidant and operate at temperatures well above ash slagging conditions to assure reasonable carbon conversion and to facilitate ash removal in molten form from the gasifier (Higman and van der Burgt, 2003). To maintain high temperature (about 1250–1600oC), the oxygen-to-fuel ratio is higher than for other kinds of gasifiers. At the high operating temperature, only small amounts of methane are produced and the concentration of other hydrocarbons in the syngas is negligible to zero.


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Entrained-flow gasifers can be slurry-feed or dry-feed gasifiers. Slurryfeed gasifiers have higher operating pressure than dry-feed ones because the pressure limit of lock-hoppers used in dry-feed is lower than that of a slurry pump. Thus, slurry-feed enables higher syngas production capacity. However, the water in slurry needs to be evaporated and heated to the operating temperature by using part of the feedstock, which has a penalty on the cold gas efficiency of the process. A slurry-feed entrained-flow gasifier can be single-stage, such as the General Electric (previously Texaco) design, or two-stage, such as the Conoco–Phillips E–Gas design. For a slurry-feed single-stage gasifier, the gasification normally takes place at temperatures between 1250 and 1600oC and at a pressure of about 30 bar (Tampa Electric, 2002; Higman and van der Burgt, 2003). Coal slurry and oxidant are introduced at the top of the gasifier, and syngas rich in H2 and CO is generated. The hot syngas with molten ash is cooled and sent to a wet scrubbing unit to remove particles. The slag is quenched by water and removed from the bottom of the quench chamber. In a slurry-feed two-stage entrained-flow gasifier, the coal slurry is split into two parts, with one part injected with oxidant to the first stage and the remaining part with slurry only injected to the second stage. The hot syngas from the first stage reacts with the remaining slurry and provides heat for the endothermic reactions in the second stage. The sygnas produced in a two-stage gasifier has relatively higher methane content and thus higher caloric value than the one produced in a single-stage gasifier because of lower temperature in its second stage (Rezaiyan and Cheremisinoff, 2005). For a slurry-feed single-stage entrained-flow gasifier, two types of raw syngas cooling methods are commercially available, including water quench and syngas cooler (radiant only or radiant and convective coolers). In the water quench design, raw syngas from the gasification zone is cooled and saturated by quenching water. In the syngas cooler design, hot syngas is cooled in a heat exchanger, in which the reduction in sensible heat of syngas is partially recovered by generating high-temperature steam. For example, the Polk plant uses the syngas cooler design (Tampa Electric, 2002). IGCC plants with syngas coolers generally have higher efficiencies than those with water quench. However, the syngas cooler design increases system cost because of the higher equipment cost for steam generation (Frey and Akunuri, 2001; Holt, 2004). An example of a dry-feed single-stage entrained-flow gasifier is the Shell gasifier. This type of gasifier has higher operating temperature and thus a higher carbon conversion efficiency than a slurry-fed gasifier. However, it has relatively lower operating pressure because of pressure limitations of dry-feed technologies (Higman and van der Burgt, 2003; Maurstad, 2005). Entrained-flow gasifiers have great fuel flexibility because of high gasification temperature. For low-rank coals with high moisture and ash



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content, however, the current entrained-flow gasifiers would have lower efficiency and higher cost than those with bituminous coal as the feedstock (Holt and Todd, 2003). The high-moisture and high-ash coal has lower energy density compared to bituminous coal and thus more oxygen is consumed. For dry-feed gasifiers, the high-moisture coal requires more heat for coal drying. Fluidized-bed gasifier In a fluidized-bed gasifier, solid fuel is broken into small pieces and introduced over a gas distributor plate through which oxidant flows upward. Hence, the fuel particles are suspended by the upward-moving oxidant and undergo turbulent movement, including back-mixing. The turbulent mixing promotes a uniform temperature in the fluidized bed. Because fluidized-bed gasifiers would plug if ash were to melt, the bed temperature must be below the ash melting or slagging temperature. Either purified oxygen or air can be used as the oxidant. The feedstock is dried and pyrolysed rapidly to release its volatile matter, which burns and supplies the heat for the endothermic gasification reactions. The raw syngas flows through a cyclone to remove particles. The removed particles containing char and ash are recycled to the reaction zone. Fluidizedbed gasifiers typically operate at temperatures between 900 and 1050oC, which is below the softening point of ash (Higman and van der Burgt, 2003). The major advantages of fluidized-bed gasifiers include their fuel flexibility resulting from good mixing of feedstock and oxidant to ensure efficient heat and mass transfer, and their ability to deal with small particles. One disadvantage is the removal of unreacted coal particles together with the ash, which leads to lower carbon conversion efficiency than other gasifiers. The lower operating temperature of fluidized-bed gasifiers leads to higher methane and tar contents in the product gas than that of entrainedflow gasifiers (Holt, 2004). When substantial CO2 capture is required, high methane content would affect CO2 capture efficiency because methane cannot be easily converted to CO2 in the water–gas shift reaction. Fluidizedbed gasifiers are best suited for reactive fuels that do not agglomerate, or ‘cake’, in the fluidized bed. The major features of a fluidized-bed gasifier are summarized in Table 3.2. A typical example of a fluidized-bed gasifier is Kellogg Rust Westinghouse (KRW) gasifier, which is used at the Pinon Pine plant (Rezaiyan and Cheremisinoff, 2005). Moving-bed gasifier In moving-bed gasifiers, also referred to as a ‘fixed-bed’ gasifiers, oxidant and steam are introduced in the lower part of the gasifier and flow vertically


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upward, while feedstock is introduced at the top of the gasifier. The feedstock is heated by up-flowing hot syngas. Volatile components are driven off from the feedstock in the upper part of the gasifier reactor vessel and are partially gasified. The remaining char moves towards the bottom of the gasifier and is combusted in the bottom zone of the reactor. The heat from the combustion zone provides thermal energy for the endothermic gasification reactions, which occur in the middle portion of the gasifier. A typical outlet gas temperature of a moving-bed gasifier is between 425 and 650oC (Higman and van der Burgt, 2003). At this temperature, heavy hydrocarbon compounds, such as tars and oils, will not be cracked. Therefore, typically a downstream condenser is used to remove heavy hydrocarbon compounds, leading to a process condensate stream that requires treatment. Furthermore, a relatively large amount of methane is produced because of the low syngas outlet temperature. Moving-bed gasifiers can be slagging or dry ash gasifiers. Examples are the British Gas/Lurgi (BGL) slagging gasifier and the Lurgi dry ash gasifier. The combustion zone temperature in dry ash gasifiers (about 10008C) is much lower than that in slagging gasifiers (about 20008C). Therefore, dry ash gasifiers are more suitable for reactive feedstock, such as lignite, rather than bituminous coal. The oxygen consumption of moving-bed gasifiers is lower than that of other types of gasifiers because of efficient heat transfer from counter-current flow and the relatively low operating temperature (delaMora et al., 1985). This kind of gasifier is suitable for handling large particles. Fine particles tend to be entrained with the exiting syngas and can block the syngas flow path (Simbeck et al., 1983; Higman and van der Burgt, 2003).

3.2.2 Water–gas shift (WGS) reaction To facilitate CO2 capture from syngas, a key design goal is to convert CO in the raw syngas to CO2, which can be separated by using effective and proven techniques to produce a CO2-rich gas. The purified CO2-rich gas can be compressed and injected to a reservoir for the purpose of sequestration. A WGS reactor is used to convert CO to CO2 for syngas produced from hydrocarbon feedstocks. The WGS reaction is exothermic and thus lower temperature favors CO conversion. However, at low temperature, the reaction rate is low. Multiplestage catalytic high-temperature shift (HTS) and low-temperature shift (LTS) reactors have been investigated, which can achieve high CO conversion efficiency and relatively high reaction rates (Chiesa et al., 2005a; Hiller et al., 2006). The HTS typically operates at temperatures between 300 and 5108C, and the LTS often operates between 180 and 2708C. In a two-stage WGS process of an IGCC system, syngas from the water



65

scrubbing unit enters the HTS reactor with steam from the steam cycle, where about 85–92% of the CO in syngas is converted. The syngas from the HTS reactor is cooled and sent to a LTS reactor, where the CO conversion can reach up to about 97–98% (Chiesa et al., 2005a). For clean gases with only small quantities of sulfur or hydrocarbons, iron–chromium oxidebased catalysts are often used in the HTS reaction and copper–zinc– aluminum oxide-based catalysts are available for the LTS reaction (Hiller et al., 2006). For syngas from coal gasification, which contains sulfur and hydrocarbons, cobalt–molybdenum-based catalysts are used at temperatures between about 200 and 5008C (Twigg, 1997; Hiller et al., 2006). Membrane-based WGS reactors are in development (Bracht et al., 1997). In these reactors, the WGS reaction takes place on a membrane containing a catalyst. The produced H2 permeates selectively through the membrane during the shift reaction process. Therefore, the chemical equilibrium of the shift reaction moves more towards the product side because of the H2 removal. Design studies have indicated that membrane WGS reactors may be more cost-effective than conventional WGS reactors (Bracht et al., 1997; Amelio et al., 2007). However, membrane WGS reactors have not been commercially applied in IGCC plants and are still in an early development phase.

3.2.3 Gas turbine High-pressure gaseous fuel, such as syngas from coal gasification, is combusted with air from the gas turbine compressor. The most typical pollutant of concern is NOx, which is produced when air is heated to a higher temperature and at high pressure. A common technique for preventing NOx emissions is to reduce peak temperature in the combustor by adding a thermal diluent, such as water, steam or nitrogen (RatafiaBrown et al., 2002a; Holt, 2003). The current state-of-practice gas turbines used in existing IGCC plants are F class. For example, both the Polk and Wabash River IGCC plants use GE 7FA gas turbines (Wabash River Energy Ltd, 2000; Tampa Electric, 2002). Current F class technology has a simple cycle efficiency ranging from 36 to 38.5% and combined cycle efficiency from 56 to 58% (Lebedev and Kostennikov, 2008). In IGCC plants without CO2 capture, the syngas sent to the gas turbine is rich in both CO and H2. For IGCC plants with substantial CO2 capture, the fuel for the gas turbine would be syngas rich in H2. Hydrogen-rich syngas-fired gas turbine Removal of CO2 from syngas leads to about 10% loss in lower heating value (LHV) because CO in the raw syngas is shifted to H2, and H2 has a lower


66


volume basis heating value than CO (Shah et al., 2005). Compared to gas turbines fired with syngas containing both CO and H2, gas turbines fired with syngas rich in H2 require more syngas to maintain the nominal output of gas turbine and thus more feedstock is required for the overall system. Todd and Battista (2000) have reported a gas turbine test with 46–95% H2 in fuel gas. The test indicated that for an increase in the H2 content of the syngas, the amount of steam injection needed to maintain a constant NOx emissions level increased. Hydrogen-rich syngas firing also leads to a higher water content of gas turbine exhaust gas, which leads to higher heat transfer capabilities than the exhaust gas from syngas without CO2 capture (Chiesa et al., 2005b). However, the high moisture content in exhaust gas resulting from steam injection and hydrogen combustion could significantly shorten turbine bucket or rotating blade life. Siemens has tested its F class machines with H2 content ranging from 30 to 73% in fuel gas (Brown et al., 2007). The test results showed that their emissions and operation targets could be achieved even when the CO2 capture was as high as 90%. NOx emissions control Nitrogen oxides formation occurs for any fuel burned with air because of high-temperature reactions involving O2 and N2 in the combustion air, and increases with temperature and residence time. Currently, three types of technologies are available for NOx emissions control in gas turbine operations, namely: (i) improved premixed combustion, such as dry low NOx (DLN) burner and catalytic combustion; (ii) dilution of combustion gases in the flame, to reduce peak flame temperature, using steam, H2O, N2, or a mix; (iii) post-combustion removal, such as selective catalytic reduction (SCR) and Sconox process (Todd and Battista, 2000; Chiesa et al., 2005b). DLN burners are designed to mix air and fuel before the combustion to achieve a lean and uniform air-to-fuel ratio. The main goal of DLN burners is to avoid hot spots that have poorly mixed fuel-to-air ratios and that lead to localized high peak temperatures, leading to disproportionately high NOx production. DLN burners operate at fuel lean conditions, in order to limit the peak flame temperature. Catalytic combustors speed up combustion kinetics, thereby enabling fuel to burn at lower temperatures, which in turn reduces the amount of NOx formation. Although DLN is a common commercially available technology, catalytic combustors are not widely deployed. Syngas fuel for gas turbines has H2 content varying from 8.6 to 61% (Brun et al., 2002). Klara (2007) indicates that syngas with 90% CO2 removal could have a H2 content as high as 90%. There is some concern that DLN and catalytic combustors may not be appropriate for use with fuels that are rich in H2, since H2 has a fast reaction rate and there may be



67

potential for a flame to ignite upstream of the desired combustion zone (Chiesa et al., 2005b). Fuel dilution is widely used in current IGCC plants for NOx control, such as N2 injection in the Polk IGCC and steam dilution in Wabash River IGCC plant (Wabash River Energy Ltd, 2000; Tampa Electric, 2002). The use of thermal diluents is expected to be a practical approach for mitigating NOx emissions for H2-rich syngases. Todd and Battista (2000) reported that gas turbine tests with steam and N2 dilution achieved NOx emissions below 10 ppm for syngas with 20–90% CO2 capture. Post-combustion removal options, such as SCR, can be combined with thermal dilution to achieve even lower NOx emissions levels. SCR is a widely used technology that has been applied to large gas turbines. SCR is capable of NOx reduction efficiencies between 70 and 90%. It is considered the most likely post-combustion NOx control candidate for use with IGCC syngas-fired gas turbine exhaust (Ratafia-Brown et al., 2002a). In the SCR process, ammonia (NH3) is injected into the exhaust gas and the NOx selectively reacts in the presence of a catalyst with NH3 and O2 to form N2 and H2O. The optimum temperature range is 250–427oC (US Environmental Protection Agency, 2003).

3.3

Applicable CO2 capture technologies

For IGCC systems, pre-combustion CO2 control schemes are generally considered to be more economical than the post-combustion CO2 control methods that would be used in PC plants (Holt, 2004; Klara, 2007). For precombustion control, CO2 can be captured by the following methods, including: (i) physical and chemical absorption; (ii) membranes separation; and (iii) cryogenic separation (Murai and Fujioka, 2008). Selection of suitable CO2 capture technologies depends on many factors, such as CO2 partial pressure, CO2 recovery and purity requirements, limitations of capture methods, and costs.

3.3.1 Physical and chemical absorption Physical and chemical absorption have been extensively investigated for CO2 capture in IGCC systems (Doctor et al., 1994; Griffiths and Scott, 2003; Klara, 2007). Syngas that has undergone WGS would be sent to a physical or chemical absorption unit to remove CO2 and other acid gases. In the physical absorption process, CO2 is removed by dissolving CO2 in a solvent. The current widely used physical solvents include liquid methanol, such as the Rectisol process, and a glycol solvent (dimethyl ether of polyethylene glycol), such as the Selexol process (Nexant, 2006; Klara, 2007). The glycol solvent process is estimated to be a better option with lower cost for IGCC


68


systems (Doctor et al., 1994; Breckenridge et al., 2000). The liquid methanol process is complex and needs refrigeration of solvents, which leads to higher cost. Furthermore, the power consumption for refrigeration leads to an energy penalty for the overall system (Korens et al., 2002). The low operating temperature of the liquid methanol process results in a lower solvent circulation rate and lower net power requirement compared to the glycol solvent process. IGCC systems using a two-stage Selexol process for CO2 capture have been evaluated by Klara (2007). Syngas from the WGS process is cooled and enters the first stage of the Selexol process to remove H2S, and is then sent to the second stage to remove 95% of the CO2 in syngas. In chemical absorption methods, CO2 is removed by reaction with a solution (Hiller et al., 2006). A typical chemical solvent is methyl diethanol amine (MDEA) (Korens et al., 2002). Chemical solvents have better performance than the physical solvents at low CO2 partial pressure. Thus, chemical solvents may have a niche for air-blown IGCC plants, in which the CO2 in syngas is diluted by N2 and thus has a lower partial pressure than for oxygen-blown systems. The CO2 partial pressure of the WGS shifted syngas in oxygen-blown IGCC plants is estimated to be 12–20 bar (Klara, 2007). Because the physical solvent solubility is proportional to CO2 partial pressure (Hiller et al., 2006), physical solvents may have better performance over chemical solvents for CO2 capture in oxygen-blown IGCC plants. Chemical solvents require a large amount of heat for regeneration, whereas physical solvents can be partly stripped by pressure drop and low heat is needed (Hiller et al., 2006).

3.3.2 Membrane separation Different kinds of membranes have been used to separate CO2 from other components of syngas, especially H2. They include CO2-selective membranes, such as polyvinylamine with the main permeate being CO2, and H2selective membranes, such as polymer and ceramic membrane with the main permeate being H2 (Kaldis et al., 2004; Grainger and Hagg, 2008). The driving force for the membrane separation is pressure differential across a permeable membrane. High partial pressure of the permeate component in the syngas favors the separation process. Membrane separation can be used downstream of a WGS reactor and a sulfur removal process. A CO2selective membrane used downstream of the WGS and the sulfur removal unit is estimated to be capable of achieving greater than 85% CO2 recovery at 95% purity (Grainger and Hagg, 2008). The total plant cost of an IGCC system with a CO2-selective membrane (85% CO2 recovery) is estimated to be about 15% higher than that with a two-stage Selexol process (90% CO2 recovery) (Klara, 2007; Grainger and Hagg, 2008). The H2 loss to the CO2 product stream is higher in the membrane process than that in a Selexol



69

process, which leads to lower power output and thus higher cost. For the H2-selective membrane, the permeated H2 is produced at near-atmospheric pressure, which requires compression before it is sent to the gas turbine combustor and thus increases the overall power consumption (Kaldis et al., 2004). Membrane technology is still in an early phase of development and is not yet commercialized.

3.3.3 Cryogenic separation Cryogenic separation involves gas refrigeration so that the CO2 can be liquefied and separated from other gases. The advantage is that this process produces a liquid CO2 ready for transportation by pipeline for sequestration. The major disadvantage is the large amount of energy required for refrigeration (Burr and Lyddon, 2008).

3.4

Applicable emissions control technologies

In this section, the main emissions control technologies for coal IGCC plants are introduced, including particulate matter, mercury, and acid gas removal technologies.

3.4.1 Particulate matter removal In IGCC systems, raw syngas typically has PM consisting of unreacted carbon and fly ash. The PM needs to be removed to avoid erosion or deposition problems for downstream equipment, such as damage to gas turbine blades (Oakey et al., 2004). In Table 3.3, the main PM control methods used in current IGCC systems are listed, including wet scrubbing, cyclones, and candle filters. Wet scrubbing has been commercially used in the Polk plant (Tampa Electric, 2002). In the wet scrubbing process, syngas contacts with water spray to remove most of the particles, hydrogen chloride (HCl), and NH3. The syngas from the scrubber is saturated with water. The PM in the blowdown black water settles out, and the remaining water is referred to as gray water. Most of the gray water is recycled to the water scrubber (Tampa Electric, 2002). The PM removal efficiencies of wet scrubbing can reach 99.9% for particles over 2 μm and between 95 and 99% for particles over 1 μm (Rezaiyan and Cheremisinoff, 2005). Cyclone filters are primarily used for removing bulk PM from gas streams. Syngas with PM enters a cyclone, which forces the PM to separate from the gas flow by centrifugal force. Cyclones have been used with fluidized-bed and entrained-flow gasifiers (Rezaiyan and Cheremisinoff, 2005). The char and other PM captured in cyclones can be recycled to


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Table 3.3 Applications and characteristics of particulate matter (PM) removal technologies Technology

Application in IGCC plants

Development status

Control efficiency

Operational characteristics

Wet scrubber

Tampa Polk Station, Wabash River Repowering, Nuon IGCC, ELCOGAS

Commercial

70 to > 99%

4 to 370oC

Cyclone

Nuon IGCC, ELCOGAS

Commercial

30 to 90% for Ineffective with PM10, and 0 to fine particles 40% for PM2.5 capture

Candle filter (ceramic or metallic)

Wabash River Repowering, Nuon IGCC, ELCOGAS

Demonstration > 99.9%

Hightemperature fabric filter (Baghouse filter)

Some biomass Demonstration 99 to 99.9% gasification plants

Inlet gas temperature should be 250 to 500oC Gas needs to be cooled to below 300oC; tar needs to be removed to prevent tar condensation

Source: Tampa Electric (2002); Wabash River Energy Ltd. (2000); Korens et al. (2002); Rezaiyan and Cheremisinoff (2005); Rich et al. (2003).

gasifiers to improve carbon conversion. Cyclones are effective at removing larger particles, but ineffective at removing small particles. Therefore, in practice, cyclones are generally combined with other PM control methods, such as candle filters, wet scrubbing, or both (Wabash River Energy Ltd, 2000; Hannemann et al., 2002). Candle filters have been used for fine particle removal in IGCC plants, such as Wabash River, Buggenum, and ELCOGAS plants (Wabash River Energy Ltd, 2000; Scheibner and Wolters, 2002; Hannemann et al., 2003). Candle filters can remove particles in the range 0.5–100 μm. Their design efficiency is typically greater than 99.9% (Wabash River Energy Ltd, 2000; Korens et al., 2002). A candle filter consists of a filter vessel and porous ceramic or metal tubes (‘candle elements’) mounted in tube sheets. The syngas flows through the elements and the tubes. Candle filters are cleaned by periodically passing pulsing clean gas to discharge the PM from the outside walls. Candle filters are designed for hot and dry PM removal and thus are typically used with dry syngas cooling. The captured particles can be recycled directly to the gasifier. There is reduced process waste water generation compared to wet scrubbing.



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Candle filters use ceramic or sintered metal as materials. Ceramic filters generally have lower availability than metallic filters because of candle breakage (Korens et al., 2002). Some IGCC plants have cyclones upstream to reduce the PM load on the candles. Downstream wet scrubbers are usually added as back-up in case candle breakage occurs. The Wabash River plant originally used ceramic candle filters and replaced them with metallic elements to avoid breakage problems (Korens et al., 2002). Other PM control methods include baghouse filters. Baghouse filters have been used in some biomass-fueled gasification plants, but not yet in coalfueled IGCC plants. Baghouse filters typically require inlet gas temperatures of less than 3008C (Rezaiyan and Cheremisinoff, 2005). This temperature constraint would require cooling of the syngas prior to the filtering, thereby leading to a penalty on plant thermal efficiency.

3.4.2 Mercury removal Mercury is a hazardous air pollutant for which emission regulations have been developed in recent years. An activated carbon bed has been demonstrated for mercury removal at Eastman Chemical coal-to-chemicals gasification plant in Tennessee for over 20 years, with a removal efficiency of between 90 and 95% (Parsons, 2002; Denton, 2003). In the activated carbon bed, the carbon is impregnated with sulfur at a concentration of between 10 and 15 wt% (Parsons, 2002). Most of the mercury in the syngas is in elemental form. The elemental mercury reacts with the sulfur in the bed to form mercury sulfide (HgS). The HgS on the spent carbon is stable, and the best option currently available is to dispose of it. The spent carbon can also be incinerated and the mercury can be recovered by cooling and condensation. In a design study by Parsons (2002), an activated carbon bed located downstream of syngas cooling and upstream of acid gas removal would operate at a temperature of approximately 38oC, since low temperature is favored for a high level of mercury removal. A disadvantage of activated carbon is that it cannot be regenerated.

3.4.3 Acid gas removal The principal goal of acid gas removal processes in current IGCC plants is to remove sulfur compounds from syngas. The currently applied sulfur removal technologies for IGCC plants include chemical solvents, physical solvents, or a mixture of both. The principal chemical solvents are aqueous amines, such as MDEA (Korens et al., 2002). The widely used physical solvents include methanol used in the Rectisol process and dimethyl ether of polyethylene glycol used in the Selexol processes (Weiss, 1998; Breckenridge et al., 2000). A widely used mixed chemical/physical process is Sulfinol,


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Table 3.4

Applications and characteristics of acid gas removal technologies

Solvents

Application Operation in IGCC condition plants

MDEA

Polk, Wabash River, ELCOGAS, Nakoso

Selexol

Cool Water 0 to 408C > 99% and > 20 bar

Rectisol

Vresova

Removal Sulfur in efficiency cleaned syngas

About 40 to > 98% 1208C and ambient to intermediate pressure

10 to 708C > 99.9% and > 20 bar

Sulfinol-D Buggenum 5 to 408C and > 98.5% and > 5 bar Sulfinol-M

Comments

100 ppmv

COS removal is limited. A COS hydrolysis reactor needs to be used upstream

10 to 15 ppmv

The COS solubility is low and a COS hydrolysis reactor may be required if high sulfur removal is required

0.1 ppmv

High solubility of COS and no COS hydrolysis reactor is needed, high cost because of refrigeration requirement

< 40 ppmv Higher COS solubility than the amine solvent. An upstream COS hydrolysis unit is likely to be required if deep H2S removal is required

Source: ENEA et al. (2005); Korens et al. (2002); Higman and van der Burgt (2003); de Kler (2007); Denton (2003); Breckenridge et al. (2000).

which uses a mixture of sulfolane (tetra-hydrothiophene dioxide) and an aqueous amine (Korens et al., 2002). Major applications and characteristics of acid gas removal technologies used in IGCC plants are summarized in Table 3.4. MDEA is widely used for acid gas removal in IGCC plants, such as Polk, Wabash River, ELCOGAS, and Nakoso (Ratafia-Brown et al., 2002a; Ishibashi and Shinada, 2008). In an MDEA process, syngas and MDEA flow counter-currently in an absorber. Acid gas is removed by forming a loose chemical bond between acid gas components and the MDEA. The rich solvent loaded with acid gases is regenerated in a stripping tower by steam heating to release acid gases. The Polk plant uses a 25–50% water solution of MDEA to remove about 99% of H2S from the syngas (Tampa Electric, 2002). Both CO2 and H2S react with MDEA and thus IGCC plants that



73

have high CO2 levels in syngas might not be able to reduce syngas H2S concentration below 100 ppm (Korens et al., 2002). The MDEA process generally has low capital cost compared to physical solvent processes when the syngas pressure is lower than 30 bar and if it is not necessary to achieve very high removal efficiency (Korens et al., 2002). However, it requires larger amounts of heat for regeneration as a chemical solvent, which reduces the overall system efficiency. The Selexol process uses a physical solvent, a mixture of dimethyl ether of polyethylene glycol, to remove acid gases. This process was used in the Cool Water plant (Breckenridge et al., 2000; Ratafia-Brown et al., 2002a). Acid gases are absorbed by the solvent at room temperature and at pressures of higher than 34 bar (Breckenridge et al., 2000). The rich solvent is flashed or stripped by steam or clean syngas to release and recover the acid gases in a concentrated side stream. The sulfur level can be reduced to 10–15 ppmv (Korens et al., 2002). The Rectisol is another process using a physical solvent, liquid methanol. Rectisol has been used globally for gas treating and is used in the Vresova coal-fueled IGCC plant (Korens et al., 2002; Luby and Susta, 2007). Sulfur and CO2 compounds are typically absorbed by liquid methanol at approximately 10 to 70oC at pressures higher than 20 bar (ENEA et al., 2005). The acid gases concentration in cleaned syngas can reach very low levels and thus this process is widely used for systems that require highefficiency sulfur removal (Korens et al., 2002). Compared to chemical solvents, physical solvents have higher loading capacity for acid gas at high acid gas partial pressure, higher selectivity for H2S and COS over CO2, more stability, and lower heat requirement for solvent regeneration (Korens et al., 2002). The MDEA or amine processes will not remove COS, and the Selexol process has low COS solubility. Therefore, a COS hydrolysis unit, which is used to convert COS to H2S, is usually used upstream of the amine or Selexol process. The Rectisol process has high COS solubility and thus no COS hydrolysis reactor is needed (ENEA et al., 2005). The major advantages of the Rectisol process include its ability to achieve very high sulfur removal in a single step, use of a readily available solvent, and flexibility in process configuration. However, it is more expensive than the amine or Selexol processes because of its complexity and refrigeration requirements (Korens et al., 2002; Denton, 2003). The Sulfinol process is a combination process that uses a mixture of amines and a physical solvent (sulfolane). The Sulfinol solvents allow higher acid gas loading and lower energy requirement for regeneration than those of pure chemical solvents (Korens et al., 2002). Sulfinol-D uses diisopropanolamine (DIPA) and Sulfinol-M uses MDEA. When a high degree of H2S selective removal is required, Sulfinol-M is used and it can produce a


74


treated gas with less than 40 ppmv sulfur (Korens et al., 2002). Sulfinol-M has been used in the Buggenum plant (Hannemann et al., 2002). Syngas flows counter-currently with the Sulfinol solvent in an absorber tower. The rich solvent-loaded acid gas enters a regenerator and is heated to discharge the acid gases.

3.4.4 Sulfur recovery and tail gas treatment In most IGCC plants, the H2S from the acid gas removal can be converted to elemental sulfur, or recovered as sulfuric acid. A typical elemental sulfur recovery technology is the Claus process, which has been used in Wabash River, Buggenum, and ELCOGAS plants (Wabash River Energy Ltd, 2000; Hannemann et al., 2002; Hannemann et al., 2003). One third of the H2S in the acid gas stream is converted to sulfur dioxide SO2 and water vapor in a furnace by partial oxidation with oxygen. The SO2 reacts with the remaining H2S to generate elemental sulfur and H2O. A waste heat boiler is used to recover the heat from the hot exhaust stream to produce high-pressure steam. The sulfur is condensed and low-pressure steam is generated. The condensed sulfur is collected as a molten liquid to obtain high-purity byproduct. The off-gas from the condenser goes to several catalytic conversion stages to recover the remaining sulfur. The overall sulfur recovery efficiency is greater than 98% in the Wabash River plant (Wabash River Energy Ltd, 2000). The sulfur recovery efficiencies of a Claus plant decrease with a decrease in the inlet H2S concentration. If the H2S content is lower than 15%, it will lead to unstable temperature in the furnace and results in low sulfur recovery efficiencies and high cost (Korens et al., 2002). A sulfuric acid by-product recovery process is used in the Polk plant (Tampa Electric, 2002). In the sulfuric acid plant, the H2S is converted to SO2 in a furnace under a vacuum condition. A waste heat boiler is used to cool the hot gas from the furnace and generate medium-pressure steam. The gas is further cooled and dried. The gas enters three stages of reactors. SO2 in the gas is oxidized to sulfur trioxide (SO3). The converted gas enters absorbing towers, where a strong sulfuric acid solution with 98% purity is used as the solvent to absorb SO3 and the acid purity is increased to 98.5%. The sulfur recovery efficiency is over 99.5% at the Polk plant (Tampa Electric, 2002). Tail gas treatment (TGT) is generally required when the sulfur recovery requirement is over 99.8%. A widely used TGT process is the Shell Claus off-gas treating (SCOT) process (Korens et al., 2002). This process consists of a catalytic hydrogenation/hydrolysis step and an amine scrubbing unit. The tail gas from the Claus process is treated in a catalytic reactor to reduce the sulfur compounds, such as SO2 and COS, to H2S via hydrogenation or hydrolysis. The gas is cooled and enters an amine scrubbing unit. The acid gas-rich solution is regenerated in a stripping column. The treated tail gas



75

can be compressed and sent, with the clean fuel gas, to the combined cycle unit. The acid gas from the stripper is recycled back to the Claus plant for further conversion of the H2S.

3.5

Advantages and limitations of coal IGCC plants

The major advantages and limitations of coal IGCC plants are described in this section.

3.5.1 Advantages of coal IGCC plants The major advantages of IGCC plants include fuel flexibility, and the potential for high efficiency and low emissions (Ratafia-Brown et al., 2002a; Nexant, 2006). If CO2 capture is required, another potential advantage of IGCC plants is lower cost than PC plants. The high temperature and high pressure of the gasification process mean that some low-value fuels, including petroleum coke, biomass, and municipal solid wastes, can be converted into syngas by gasification. The feedstock flexibility feature of IGCC reduces the dependence on a specific fuel for power generation and enables diversity of fuel sources. The thermal efficiencies of IGCC plants range from 39 to 43%, which can be higher than those of conventional PC plants, which range from 35 to 42% (Breault, 2008). IGCC plants may have environmental advantages over conventional subcritical PC plants. For example, in a design study, the emissions of SO2, NOx, PM, and volatile organic compounds (VOCs) of an IGCC plant were estimated to be 41%, 67%, 48%, and 57% of the corresponding emissions from a subcritical PC plant, respectively (Nexant, 2006). In Table 3.5, the performance, emissions, and costs of a generic IGCC plant are compared with a supercritical PC plant, both without and with CO2 capture. For both cases, without and with CO2 capture, the IGCC plant has higher efficiency. The IGCC plant also has lower emissions for NOx, PM, Hg, and CO2 on a net power output basis than those of the PC plant because of higher net plant efficiency and higher removal efficiencies. The mercury control efficiency for the IGCC plant is assumed to be 95% based on achievable removal efficiency in practice (Klara, 2007). For the bituminous coal fired PC plant, Hg control was assumed to be 90%, which is the mid-point of a range of observed efficiencies from 83.3 to 98% based on Hg co-capture in combination with a fabric filter and a wet flue gas desulfurization (FGD) scrubber (Klara, 2007). For SO2 emissions, the IGCC plant without CO2 capture has a lower emission rate than the PC plant without CO2 capture. The removal efficiency is assumed to be 99.7% for IGCC. FGD technology may be capable of reaching


76


Table 3.5 Comparison of generic integrated gasification combined cycle and pulverized coal power plants Integrated gasification combined cyclea

Description

Pollution control methods:c Sulfur control Selexol/MDEA/Sulfinol Nitrogen control Nitrogen dilution Particulate control Water scrubbing Mercury removal Activated carbon 2nd stage of Selexol CO2 capture Without CO2 With CO2 capture capture

Performance:d

Cost (2007 US dollars): Total plant cost, $/kW Cost of electricity, $/MWhf Cost of CO2 avoided, $/metric tong

Wet FGD Low-NOx burner and SCR Fabric filter Fabric filters and FGD Amine Without CO2 capture

With CO2 capture

530 32.1 4430

550 39.1 5440

546 27.2 10 440

46.7 225 27.9

46.1 234 34.4

335 277 51.2

Negligible 398 73.9

0.0022 778

0.0028 99

0.0045 804

0.0065 115

1840 78

2500 106

1570 63

2870 115

Net power output, MWe 633 Efficiency, % HHV 39.5 Raw water usage, 3850 gallon/min Emissions:e SO2 emissions, g/MWh NOx emissions, g/MWh Particulate matters (PM), g/MWh Hg emissions, g/MWh CO2 emissions, kg/MWh

Pulverized coal (PC) power plantsb

35

73

Note: aEntrained-flow gasifier-based IGCC: the data are based on average values from different cases. b Supercritical PC. c MDEA: methyl diethanol amine; Sulfinol: Sulfinol-M, mixture of sulfolane and MDEA; SCR: Selective catalytic reduction; FGD: Flue gas desulfurization. d The design coal is Illinois No. 6: 10.91 wt% ash, 2.82 wt% sulfur, and 30 506 kJ/kg HHV (dry basis); HHV: higher heating value; For CO2 capture cases, the nominal capture efficiency is assumed to be 90%. e Based on net power output. f The capacity factor is assumed to be 80% for IGCC and 85% for PC plants. g The cost of CO2 avoided is defined as the difference in the 20-year levelized costof-electricity between controlled and uncontrolled like cases, divided by the difference in CO2 emissions in kg/MW h. Source: Klara (2007).

over 99% SO2 removal efficiency. A more reliably achievable SO2 removal rate of 98% was assumed for the PC plant (Klara, 2007). For the CO2 capture cases, the amine system used for CO2 capture in the PC plant is estimated to absorb almost all SO2, resulting in negligible emissions (Klara, 2007).



77

Comparing the cases without and with CO2 capture, the net efficiency decreases about 7% on a relative basis for the IGCC plant, while it decreases about 12 % on a relative basis for PC plants. The IGCC plant uses a two-stage Selexol process for acid gas and CO2 removal and PC plant uses an amine system for CO2 removal. The auxiliary energy consumption is larger for the amine process than that for the physical solvent process. For the PC plant, there is higher auxiliary load for CO2 compression compared to the IGCC plant because of the lower pressure of exhaust gas, compared to syngas, from which CO2 is captured. The emissions of NOx, PM, and Hg increase on a g/MW h basis when CO2 capture is required because of the decrease in plant efficiencies. The SO2 emission decreases because of additional sulfur removal in the CO2 removal process. The raw water usage of an IGCC plant is about 70% that of a supercritical PC plant for the no CO2 capture case and it is 42% for the CO2 capture case. IGCC plants use both gas turbines and steam turbines for power generation, whereas PC plants use only steam turbines for all power generation and thus have larger raw water usage for cooling tower water make-up. The biggest water demand for power plants is the cooling tower make-up, which is 84–91% of the total raw water usage for IGCC plants and about 90% for PC plants (Nexant, 2006; Klara, 2007). Other water usages for IGCC plants include slurry water if gasifiers are slurry-feed, PM scrubbing, and boiler make-up. These water usages are a small percentage of the total raw water usage. With CO2 capture, the average raw water usage for both IGCC and PC plants increases, as shown in Table 3.5. The primary reason for the IGCC plant is the water usage required by the WGS reaction. For the PC plant, the large increase in water usage results from the cooling water demand in the amine process used for CO2 capture (Klara, 2007). IGCC plants have less solid waste for disposal compared to PC plants (Nexant, 2006). For a non-slagging gasifier-based IGCC plant, fly ash would be captured and recycled to the gasifier to improve carbon conversion and thus less solid waste is produced (Rezaiyan and Cheremisinoff, 2005). For a slagging gasifier-based plant, the largest solid waste generated is slag, which is typically a glass-like material and can be a marketable by-product for cement production as demonstrated in the Tampa plant (Ratafia-Brown et al., 2002a). The measured leaching for slags from moving-bed and entrained-flow gasifiers ranges from spiral-wound > plate-and-frame > tubular. In Table 6.7 the packing density of the commercially available inorganic membrane modules is shown (Baker, 2000). The single plate geometry shows a very low packing density, whereas single tubes typically range between 35 and 280 m2/m3. The packing density of most of the inorganic membrane modules of the shell-and-tube type is in the same range as the organic type: 150–300 m2/m3. In contrast to organic membranes, no commercial inorganic membranes are yet currently available in the high packing density such as spiral-wound and hollow-fibre membranes. Nevertheless, quite recently, hollow-fibre ceramic and carbon membranes were prepared by Li and coworkers (Liu et al., 2003; Li, 2005; Ismail and Li, 2008). The packing density of these membranes is in the range 500–9000 m2/m3, with an area of standard module in the range 50–150 m2. Multi-channel monolith modules (with a single element in a module)


168


Table 6.6 Commercially available membrane modules, their costs, control of concentration polarisation, and applications Membrane Cost module

Characteristics Packing density: m2/m3

Control of Applications concentration polarisation

Plate-andframe

Medium Flat sheet membranes

100–200

Good

MF, UF, RO, PV, D, ED

Spiralwound

Low

Flat sheet

700–1,000

Good

UF, RO, PV, GS

Tubular

Very high

i.d. > 5 mm

100–500

Very good

MF, UF, RO, D

Capillary

Low

i.d. 23008F for hydrated lime). Multiple injection ports in the furnace wall may be needed to ensure proper mixing and to follow boiler load swings and hence shifting temperature zones. Hydration of the free lime in the product may be required. Lime is very reactive when exposed to water and can pose a safety hazard for disposal areas. Economizer injection In an economizer injection process (shown in Fig. 7.3b), hydrated lime is injected into the flue gas stream near the economizer inlet where the temperature is between 950 and 10508F. This process is not commercially used at the present time, but has been extensively studied because it was found that the reaction rate and extent of sulfur capture (see Fig. 7.4) are comparable to FSI. However, the economizer temperatures are too low for dehydration of the hydrated lime (only about 10% of the hydrated lime forms quicklime) and the hydrate reacts directly with the SO2 to form calcium sulfite CaðOHÞ2 ðsÞ þ SO2 ðgÞ ! CaSO3 ðsÞ þ H2 OðvÞ

½7:20

This process is best suited for older units in need of a retrofit process and can be used for low-to high-sulfur coals. The advantages and disadvantages of this system are similar to the FSI process (but will not be discussed in detail, since this process is not presently being used in the power industry) with the notable exception that there is no reactive CaO contained in the waste.


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Duct sorbent injection: dry sorbent injection Dry sorbent injection (DSI), also referred to as in-duct dry injection, is illustrated in Fig. 7.3c. Hydrated lime is the sorbent typically used in this process, especially for power generation facilities. However sodium-based sorbents have been tested extensively, including full-scale utility demonstrations, and are used in industrial systems such as municipal and medical waste incinerators for acid gas control. When using hydrated lime in this process, it is injected either upstream or downstream of a flue gas humidification zone. In this zone, the flue gas is humidified to within 208F of the adiabatic saturation temperature by injecting water into the duct downstream of the air preheater (Radcliffe, 1991). The SO2 in the flue gas reacts with the calcium hydroxide to form calcium sulfate and calcium sulfite CaðOHÞ2 ðsÞ þ SO2 ðgÞ þ 12 O2 ðgÞ þ H2 O ðvÞ ! CaSO4 2H2 OðsÞ ½7:21 CaðOHÞ2 ðsÞ þ SO2 ðgÞ ! CaSO3 12 H2 OðsÞ þ 12 H2 OðvÞ

½7:14

The water droplets are vaporized before they strike the surface of the wall or enter the particulate control device. The unused sorbent, along with the products and fly ash, are all collected in the particulate control device. About half of the collected material is shipped to a landfill while the other half is recycled for injection with the fresh sorbent into the ducts (Radcliffe, 1991). The DSI system offers many of the same advantages and disadvantages that other dry systems offer (Radcliffe, 1991). The process is less complex (i.e. no slurry recycle and handling, no dewatering system, fewer pumps, and no reactor vessel) than a wet system, specifically LSFO. The humidification water and hydrated lime are injected directly into the existing flue gas path. No separate SO2 absorption vessel is necessary. The handling of the reagent is simpler than in wet systems. The costs for DSI systems are less than in wet systems since there is less equipment to install and, since there is less equipment, operating and maintenance costs are reduced. The waste product is free of reactive lime so that no special handling is required. Some of the problems encountered by the DSI system and its disadvantages, as compared to the LSFO system, are common to other dry processes. Sulfur dioxide removal efficiencies are lower (as is calcium utilization) than wet systems and range from 30 to 70% for a Ca/S ratio of 2.0. Quicklime is more expensive than limestone. When an ESP is used for particulate control, there is the potential for reduced efficiency due to increased fly ash resisitivity and dust loading in the flue gas. Additional


Advanced flue gas cleaning systems for emissions control

203

collection devices may be required. A sufficient length of ductwork is necessary to ensure a residence time of 1–2 s in a straight, unrestricted path. Plugging of the duct can occur if the residence time is insufficient for droplet vaporization, leading to increased system pressure drop. Hybrid systems Hybrid sorbent injection processes are typically a combination of FSI and DSI systems with the goal of achieving greater SO2 removal and sorbent utilization (Soud, 2000). Various types of configurations have been tested including injecting secondary sorbents, such as sodium compounds into the ductwork or humidifying the flue gas in a specially designed vessel. Humidification reactivates the unreacted CaO and can increase the SO2 removal efficiency. Advantages of hybrid processes include high SO2 removal, low capital and operating costs, less space necessary thereby lending to easy retrofit, easy operation and maintenance, and no waste water treatment (Soud, 2000). In some hybrid systems, a new baghouse is installed downstream of an existing particulate removal device (generally an ESP). The existing ESP continues to remove the ash, which can be either sold or disposed. Sulfur dioxide removal is accomplished in a manner similar to in-duct injection, with the sorbent injection upstream of the new baghouse (Rhudy et al., 1986). The potential advantages of this system include the possibility for toxic substances control since a baghouse is the last control device (this is further discussed in Chapter 8 and section 7.6), easier waste disposal, the potential for sorbent regeneration, separate ash and product streams, and more efficient recycle without ash present (Rhudy et al., 1986). The major issue is the high capital cost of adding a baghouse, although the concept of adding one with a high air-to-cloth ratio (3–5 acfm/ft2) can minimize this cost.

7.3

Selective catalytic reduction (SCR)

Selective catalytic reduction (SCR) of NOx using ammonia (NH3) as the reducing gas was patented in the US by Englehard Corporation in 1957 (DOE, 1997) and has been used commercially in Japan since 1980, in Germany since 1986, and in the US starting in the 1990s. This technology can achieve NOx reductions in excess of 90% and is now widely used in commercial applications worldwide.


204


7.3.1 Process description The SCR process uses a catalyst at approximately 570–7508F to facilitate a heterogeneous reaction between NOx and an injected reagent, vaporized ammonia, to produce nitrogen and water vapor. Ammonia chemisorbs on to the active sites on the catalyst. The NOx in the flue gas reacts with the adsorbed ammonia to produce nitrogen and water vapor. The principal reactions are (EPA, 1997b) 4NO þ 4NH3 þ O2 ! 4N2 þ 6H2 O

½7:22

2NO2 þ 4NH3 þ O2 ! 3N2 þ 6H2 O

½7:23

A small fraction of the sulfur dioxide is oxidized to sulfur trioxide over the SCR catalyst. In addition, side reactions may produce the undesirable byproducts ammonium sulfate ((NH4)2SO4) and ammonium bisulfate (NH4HSO4), which can cause plugging and corrosion of downstream equipment. These side reactions are (DOE, 1997) SO2 þ 12 O2 ! SO3

½7:24

2NH3 þ SO3 þ H2 O ! ðNH4 Þ2 SO4

½7:25

NH3 þ SO3 þ H2 O ! NH4 HSO4

½7:26

There are three SCR system configurations for coal-fired boilers and they are known as high-dust, low-dust, and tail-end systems. These are shown schematically in Fig. 7.5 (EPA, 1997b). In a high-dust configuration, the SCR reactor is placed upstream of the particulate removal device between the economizer and the air preheater. This configuration (also referred to as hot side, high dust) is the most commonly used, particularly with drybottom boilers (Wu, 2002) and is the principal type planned for the installations in the US (McIlvaine et al., 2003). In this configuration, the catalyst is exposed to the fly ash and chemical compounds present in the flue gas that have the potential to degrade the catalyst by ash erosion and chemical reactions (i.e. poisoning). However, these can be addressed by proper design as evidenced by the extensive use of this configuration. In a low-dust installation, the SCR reactor is located downstream of the particulate removal device. This configuration (also referred to as hot side, low dust) reduces the degradation of the catalyst by fly ash erosion. However, this configuration requires a costly hot-side ESP or a flue gas reheating system to maintain the optimum operating temperature. In tail-end systems (also referred to as cold side, low dust), the SCR



205

7.5 SCR configurations with typical system temperatures: (a) high-dust system; (b) low-dust system; (c) tail-end system.

reactor is installed downstream of the FGD unit. It may be used mainly in wet-bottom boilers and also on retrofit installations with space limitations (Wu, 2002). However, this configuration is typically more expensive than the high-dust configuration due to flue gas reheating requirements. This configuration does have the advantage of longer catalyst life and use of more active catalyst formulations to reduce overall catalyst cost. There are several issues that need to be considered in the design and operation of SCR systems, including coal characteristics, catalyst and reagent selections, process conditions, ammonia injection, catalyst cleaning and regeneration, low-load operation, and process optimization (Wu, 2002). Coals with high sulfur in combination with significant quantities of alkaline metals, alkaline earth metals, arsenic, or phosphorus in the ash can severely deactivate a catalyst and reduce its service life. In addition, the SO3 can react with residual ammonia resulting in ammonium sulfate deposition in the air preheater and loss of performance.


206


7.3.2 SCR configuration and catalyst composition The two leading geometries of SCR catalysts are honeycomb and plate (DOE, 1997). The honeycomb form usually is an extruded ceramic with the catalyst either incorporated throughout the structure (homogenous) or coated on the substrate. In the plate geometry, the support material is generally coated with catalyst. Plate-type catalysts have lower pressure drops and are less susceptible to plugging and fouling than the honeycomb types; however, plate-type configurations are significantly larger and more expensive. Honeycomb configurations are significantly smaller than plate types, but have higher pressure drops and plug much more easily. SCR catalysts were primarily developed by the Japanese as early as 1977. SCR catalysts for utility applications are manufactured from various ceramic materials used as a carrier, such as titanium oxide, and active catalytic components are oxides of base metals such as vanadium (V2O5) and tungsten (WO3).

7.3.3 SCR operation For optimum SCR performance, the reagent must be well mixed with the flue gas and in direct proportion to the amount of NOx reaching the catalyst. Anhydrous ammonia has been commonly used as reagent, accounting for over 90% of current world SCR applications (Wu, 2002). It dominates planned installations in the US, although numerous aqueous systems will be installed. Recently, urea-based processes are being developed to address utilizing anhydrous ammonia, which is a hazardous and toxic chemical. When urea (CO(NH2)2) is used, it produces ammonia, which is the active reducing agent, by the following reactions NH2 CO NH2 ! NH3 þ HNCO

½7:27

HNCO þ H2 O ! NH3 þ CO2

½7:28

During the operation of the SCR, the catalyst is deactivated by fly ash plugging, catalyst poisoning, and/or the formation of binding layers. The most common method of catalyst cleaning has been the installation of steam soot blowers, although acoustic cleaners have been successfully tested. Once the catalyst has been severely deactivated, it is conventional practice to add additional catalyst or replace it; however, several regeneration techniques have evolved over the last few years providing extended service life for catalysts (Wu, 2002). Low-load boiler operation can be problematic with SCR operation, specifically with high-sulfur coals. There is a minimum temperature below



207

which the SCR should not be operated; therefore, system modifications such as economizer bypass to raise the SCR temperature during low-load operation may be required (Wu, 2002).

7.4

Selective non-catalytic reduction (SNCR)

Selective non-catalytic reduction (SNCR) is a proven, commerciallyavailable technology that has been applied since 1974 (Wu, 2002). The SNCR process involves injecting nitrogen-containing chemicals into the upper furnace or convective pass of a boiler within a specific temperature window without the use of an expensive catalyst. There are different chemicals which can be used that selectively react with NO in the presence of oxygen to form molecular nitrogen and water, but the two most common are ammonia and urea. Other chemicals that have been tested in research include amines, amides, amine salts, and cyanuric acid. In recent years, ureabased reagents such as dry urea, molten urea, or urea solution have been increasingly used, replacing ammonia at many plants because anhydrous ammonia is the most toxic and requires strict transportation, storage, and handling procedures (Wu, 2002). The main reactions when using ammonia or urea are, respectively 4NO þ 4NH3 þ O2 ! 4N2 þ 6H2 O

½7:29

4NO þ 2CO ðNH2 Þ2 þ O2 ! 4N2 þ 2CO2 þ 6H2 O

½7:30

A critical issue is finding an injection location with the proper temperature window for all operating conditions and boiler loads. The chemicals then need to be adequately mixed with the flue gases to ensure maximum NOx reduction without producing too much ammonia. Ammonia slip from an SNCR can affect downstream equipment by forming ammonium sulfates. The temperature window varies for most of the reducing chemicals used but generally is between 1650–21008F. Ammonia can be formed below the temperature window and the reducing chemicals can actually form more NOx above the temperature window. Ammonia has a lower operating temperature than urea, 1560–19208F compared to 1830–21008F, respectively. Enhancers such as hydrogen, carbon monoxide, hydrogen peroxide (H2O2), ethane (C2H6), light alkanes, and alcohols have been used in combination with urea to reduce the temperature window (Lodder and Lefers, 1985). Several processes use proprietary additives with urea in order to reduce NOx emissions (Ciarlante and Zoccola, 2001). The efficiency of reagent utilization is significantly less with SNCR than with SCR. In commercial SNCR systems, the utilization efficiency is


208


typically between 20 and 60%; consequently, usually three to four times as much reagent is required with SNCR to achieve NOx reduction similar to that of SCR. SNCR processes typically achieve 20–50% NOx reduction with stoichiometric ratios of 1.0–2.0. The major operational impacts of SNCR include air preheater fouling, ash contamination, N2O emissions, and minor increases in heat rate. A major plant impact of SNCR is on the air preheater, where residual ammonia reacts with the SO3 in the flue gas to form ammonium sulfate and bisulfate (see reactions [7.26] through [7.28]) causing plugging and downstream corrosion. High levels of ammonia slip can contaminate the fly ash and reduce its sale or disposal. Significant quantities of N2O can be formed when the reagent is injected into areas of the boiler which are below the SNCR optimum operating temperature range. Urea injection tends to produce a higher level of N2O compared to ammonia. The unit heat rate is increased slightly due to the latent heat losses from vaporization of injected liquids and/or increased power requirements for high-energy injection systems. The overall efficiency and power losses normally range from 0.3 to 0.8% (Wu, 2002).

7.5

Hybrid SNCR/SCR

SCR generally represents a relatively high capital requirement whereas SNCR has a high reagent cost. A hybrid SNCR/SCR system balances these costs over the life cycle for a specific NOx reduction level, provides improvements in reagent utilization, and increases overall NOx reduction (Wu, 2002). However, there is limited experience with these hybrid systems as full-scale power plant operation to date has only been in demonstrations. They are discussed here because they have demonstrated NOx reductions as high as 60–70%. In a hybrid SNCR/SCR system, the SNCR operates at lower temperatures than stand-alone SNCRs, resulting in greater NOx reduction but also higher ammonia slip. The residual ammonia feeds a smaller-sized SCR reactor, which removes the ammonia slip and decreases NOx emissions further. The SCR component may achieve only 10–30% NOx reduction with reagent utilization as high as 60–80% (Wu, 2002). Hybrid SNCR/SCR systems can be installed in different configurations including (Wu, 2002): . . . .

SNCR with conventional reactor-housed SCR; SNCR with in-duct SCR, which uses catalysts in existing or expanded flue gas ductwork; SNCR with catalyzed air preheater, where catalytically active heat transfer elements are used; SNCR with a combination of in-duct SCR and catalyzed air heater.



7.6

209

Activated carbon injection systems

To date, ACI has shown the most promise as a near-term mercury control technology, although continuous long-term operation is required to determine the effect on plant operations. In a typical configuration, PAC is injected downstream of the power plant’s air heater and upstream of the particulate control device – either an ESP or a fabric filter. The PAC adsorbs the mercury from the combustion flue gas and is subsequently captured along with the fly ash in the particulate control device. A variation of this concept is the TOXECONTM process (discussed in more detail in Chapter 8) where, a separate baghouse is installed after the primary particulate collector (especially when it is a hot-side ESP) and air heater and PAC is injected prior to the TOXECONTM unit (i.e. TOXECON ITM). This concept allows for separate treatment or disposal of fly ash collected in the primary particulate control device. A variation of the process is the injection of PAC into a downstream ESP collection field to eliminate the requirement of a retrofit fabric filter and allow for potential sorbent recycling (i.e. TOXECON IITM configuration). The performance of PAC in capturing mercury is influenced by the flue gas characteristics, which are determined by factors such as coal type, air pollution control device configuration, and additions to the flue gas including SO3 for flue gas conditioning (Sjostrom et al., 2007). Research has shown that HCl and sulfur species (i.e. SO2 and SO3) in the flue gas significantly impact the adsorption capacity of fly ash and activated carbon for mercury. Specifically, the following findings have been reported (Feeley, 2006). . .

.

HCl and H2SO4 accumulate on the surface on the carbon. HCl increases the mercury removal effectiveness of activated carbon and fly ash for mercury, particularly as the flue gas concentration increases from 1 to 10 ppm. The relative enhancement in mercury removal performance is not as great above 10 ppm HCl. Other strong Brønsted acids such as the hydrogen halides – HCl, HBr, or HI – should have a similar effect. Halogens such as chlorine (Cl2) and bromine (Br2) should also be effective at enhancing mercury removal effectiveness, but this may be the result of the halogens reacting directly with mercury rather than the halides, thereby promoting the effectiveness of the activated carbon. SO2 and SO3 reduce the equilibrium capacity of activated carbon and fly ash for mercury. Activated carbon catalyzes SO2 to H2SO4 in the flue gas. Because the concentration of SO2 is much higher than mercury in the flue gas, the overall adsorption capacity of mercury is likely to be


210


7.6 Mercury removal as a function of activated carbon injection concentration. Note: legend lists power plant name: coal rank-APCD configuration (PAC type).

dependent on the SO2 and SO3 concentrations in the gas, as these form H2SO4 on the surface of the carbon. Figure 7.6 illustrates some results from conventional PAC injection tests performed through numerous DOE test programs (Feeley, 2006; Feeley and Jones, 2008). Conventional PAC injection was the focus of initial field testing and serves as the benchmark for all field PAC injection tests. This work showed that a maximum of approximately 65% mercury capture could be achieved when firing a sub-bituminous coal in a power plant using an ESP. The conventional PAC testing was followed by work with chemicallytreated PACs, which were developed for low-rank coal applications following the low mercury capture results in the initial testing. Some results from the chemically-treated PAC testing are shown in Fig. 7.7 (Feeley, 2006; Feeley and Jones, 2008). With PAC injection at 1 lb/MMacf (million actual cubic feet of flue gas), mercury removal ranges from 70 to 95% for low-rank coals. Results from testing using the TOXECONTM technology are given in Table 7.2 (fabric filter configuration) and Fig. 7.8 (ESP configuration) (Sjostrom et al., 2007). In the fabric filter configuration, mercury removals



211

Table 7.2 Demonstrated mercury removal at 2 or 5 lb/MMacf (modified from Sjonstrom et al., 2007)a Control device

ESP ESP with SO3b TOXECONTM SDA + FF (5 lb/MMacf) (5 lb/MMacf) (2 lb/MMacf) (2 lb/MMacf)

Low S, very low CI 78–95% with 40–91% with (Powder River Basin brominated brominated sub-bituminous coal or PAC PAC North Dakota lignite)

70–90%

90–95% with brominated PAC

Low S, > 50 ppm Cl (Some Texas lignites)

78–95%

40–91%

70–90%

Low S, bituminous coal 55–75%

40–91%

ND

90–95% with brominated PAC ND

Low S, bituminous coal 15–70% with SCR

NA

ND

ND

Low S, bituminous coal < 15%

NA

NA

NA

a

ESP = electrostatic precipitator; SDA = spray dryer absorber; FF = fabric filter; NA = not available; ND = not applicable or configuration unlikely. b SO3 from SO3 injection.

7.7 Mercury removal as a function of chemically-treated activated carbon injection concentration. Note: legend lists power plant name: coal rank-APCD configuration (PAC type).


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7.8 Mercury removal as a function of activated carbon injection concentration using the TOXECON IITM configuration at the Independence Station. Note: DARCO Hg is a conventional PAC whereas DARCO Hg-LH is a brominated PAC.

of 70–90% have been achieved using low-rank coals, while removal efficiencies of 50–90% are expected when using low-sulfur bituminous coals. From Fig. 7.8, 50–80% mercury reduction was achieved when injecting chemically-treated PAC at 4–5 lb/MMacf into the next-to-last ESP field (i.e. F5) and the last ESP field (i.e. F7). The improved mercury capture efficiency of the advanced chemicallytreated sorbent injection systems has given US coal-fired power plant operators the confidence to begin deploying the technology. As of April 2008, nearly 90 full-scale ACI systems have been ordered by US coal-fired power generators (Feeley and Jones, 2008). These contracts include both new and retrofit installations. The ACI systems have the potential to remove more than 90% of the mercury in many applications.

7.7

Future trends

Scrubbing technologies for SO2 capture are considered mature. Although there are on-going activities to optimize systems, as with any technology,



213

there are no major near-term technology changes expected; therefore, this section will focus on future trends for NOx and mercury control.

7.7.1 NOx control NOx control research and development currently underway can be grouped into five areas (Lani, et al., 2008) . . . . .

next-generation low-NOx burners; rich reagent injection/advanced layered technology approach; oxygen-enhanced combustion; novel enhanced combustion; SCR optimization.

Next-generation low-NOx burners Low-NOx burner (LNB) technology, which is not a post-combustion NOx control strategy and hence was not discussed in this chapter, is proven and readily available for the utility power industry. However, there is work underway in the development of the next-generation LNB that is based on the second and third generation of commercially-available LNB, but enhanced to achieve a NOx emission rate of less than 0.15 lb NOx/MM Btu (per million Btu heat input). Work is focused on low-NOx firing systems for tangentially-fired boilers and integrating LNB and SNCR for wall-fired boilers. Rich reagent injection/advanced layered technology approach Another technology under development is rich reagent injection (RRI), which uses a nitrogen-containing additive such as ammonia or urea to noncatalytically reduce NOx in the lower furnace – similar to SNCR. This technology is being focused on cyclone-fired boilers, which produce relatively high, uncontrolled NOx emissions. Combining RRI with overfire air (OFA) technology and SNCR, is known as the advanced layered technology approach (ALTA). Oxygen-enhanced combustion Replacing a small fraction – less than 10% – of combustion air with pure oxygen can enhance the NOx reduction available with LNB and OFA. The oxygen-enhanced combustion reduces NOx formation due to the creation of a more fuel-rich condition and increased flame temperature at the burner, which drives the combustion reactions toward formation of molecular


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nitrogen (N2) rather than NOx. This technology is being applied in pulverized-coal-fired boilers, cyclone-fired boilers, and fluidized-bed combustion boilers. Novel enhanced combustion Novel enhanced combustion technologies are also under development. These include technologies such as methane de-NOx and dense phase reburn (DPR). The methane De-NOx technology combines several NOx reduction strategies into an integrated system, including a novel burner design using natural gas-fired coal preheating and internal and external combustion staging in the primary and secondary combustion zones. In the DPR system, micronized coal, at a particle size of 80% minus 45 μm, is injected in the dense phase into the furnace while controlling the stoichiometry from the bottom to the top of the furnace. SCR optimization While SCR has proven to be an effective NOx control technology, catalyst deactivation and blockage requires a comprehensive catalyst management program to guide the addition and replacement of catalyst. Hence, work is underway to obtain in-situ SCR catalyst deactivation measurements.

7.7.2 Mercury capture FGD systems Although PAC injection has shown the most promise as a near-term mercury control technology, testing is underway to enhance mercury capture for plants equipped with wet FGD systems. These FGD-related technologies include: (i) coal and flue gas chemical additives with fixed-bed catalysts to increase levels of oxidized mercury in the flue gas; and (ii) wet FGD chemical additives to promote mercury capture and prevent reemission of previously captured mercury from the FGD absorber vessel. There is much interest in these activities as the use of FGD systems at coalfired power plants is expected to increase significantly over the next 15 years. Wet FGD systems, especially those associated with bituminous coal-fired power plants equipped with SCR systems, appear to be good candidates for capturing mercury. With the projected increase in wet FGD systems for bituminous coal-fired power plants, the co-benefit of capturing mercury with SO2 can be realized. Research is currently underway to evaluate technologies that facilitate mercury oxidation and to ensure that captured



215

mercury is not re-emitted from FGD systems. Research to date is encouraging. Innovative techniques Innovative techniques for mercury control that could eventually replace and/or augment the more mature technologies discussed above are currently being explored (Feeley and Jones, 2008). These technologies include MerCAPTM (an adsorption process using a fixed structure in the flue gas with sorbent regeneration and mercury recovery), utilizing partially gasified coal for mercury removal, a low-temperature mercury capture process using unburned carbon in the fly ash, pre-combustion mercury removal using thermal treatment, and new sorbent development.

7.8


Sources of other information include: . . .

7.9

US Department of Energy, National Energy Technology website where coal power systems can be found: http//www.netl.doe.gov/ US Department of Environmental Protection website: http//www.epa. gov/ International Energy Agency website: http//www.iea.org

References

Ciarlante V and Zoccola M (2001), ‘Conectiv Energy successfully using SNCR for NOx control’, Power Engineering, 105(6), 61–62. DOE (1997), Clean coal technology, control of nitrogen oxide emissions: selective catalytic reduction (SCR), topical report number 9, Washington, DC, US Department of Energy, US Governmental Printing Office. EPA (1997a), Mercury study report to Congress, Washington, DC, US Environmental Protection Agency, Office of Air Quality Planning and Standards, US Governmental Printing Office. EPA (1997b), Performance of selective catalytic reduction on coal-fired steam generating units, Washington, DC, US Environmental Protection Agency, Office of Air and Radiation, US Government Printing Office. Feeley T (2006), ‘US DOE’s Hg control technology RD&D program – Significant progress but more work to be done’, Proceedings of Conference on Mercury as a global pollutant, Mercury 2006. Feeley T and Jones A (2008), An update on DOE/NETL’s mercury control technology field testing program, DOE White Paper, www.netl.doe.gov/technologies/ coalpower/ewr/mercury/index.html. Kitto J and Stultz S (eds) (2005), Steam, its generation and use, 41st edition, Barberton, Ohio, The Babcock and Wilcox Company. Lani B, Feeley T, Miller C, Carney B and Murphy J (2008), ‘DOE/NETL’s NOx


216


emissions control RD&D program – bringing advanced technology to the marketplace’, NOx RD&D Overview, April Issue, www.netl.doe.gov. Lodder P and Lefers J (1985), ‘Effect of natural gas, C2H6, and CO on the homogenous gas phase reduction of NOx by NH3’, Chemical Engineering Journal, 30(3), 161. McIlvaine R, Weiler H and Ellison W (2003), ‘SCR operating experience of German powerplant owners as applied to challenging, US, high-sulfur service’, Proceedings of the EPRI–DOE–EPA combined power plant air pollution control MEGA symposium. Miller B (2005), Coal energy systems, Oxford, Elsevier. Miller B and Tillman D (eds) (2008), Combustion engineering issues for solid fuel systems, Burlington, Massachusetts, Academic Press. Radcliffe P (1991), Economic evaluation of flue gas desulfurization systems, Palo Alto, California, Electric Power Research Institute. Rhudy R, McElroy M and Offen G (1986), ‘Status of calcium-based dry sorbent injection SO2 control, Proceedings of the 10th Symposium on Flue gas desulfurization, pp. 9-69–9-84. Rubin E, Sonia Y, Hounshell D and Taylor M (2004), ‘Experience curves for power plant emission control technologies’, International Journal of Energy Technology and Policy, 2(1/2). Sjostrom S, Campbell T, Bustard J and Stewart R (2007), ‘Activated carbon injection for mercury control: overview’, Proceedings of the 32nd International Technical Conference on Coal utilization and fuel systems. Soud H (2000), Developments in FGD, London, IEA Coal Research. Srivastava R, Singer C and Jozewicz W (2000), ‘SO2 scrubbing technologies: a review’, Proceedings of the AWMA 2000 annual conference and exhibition. Stultz S and Kitto J (eds) (1992), Steam: its generation and use, 40th edition, Barberton, Ohio, The Babcock & Wilcox Company. Wark K, Warner C and Davis W (1998), Air pollution its origin and control, 3rd edition, Menlo Park, California, Addison Welsey Longman, Inc. Wu Z (2002), NOx control for pulverized coal fired power stations, London, IEA Coal Research.


8 Advanced flue gas dedusting systems and filters for ash and particulate emissions control in power plants B . G . M I L L E R , The Pennsylvania State University, USA

Abstract: This chapter discusses current and future control technologies for particulates and ash in the power generation sector. Current control technologies addressed include atmospheric pressure systems, which are primarily electrostatic precipitators (mostly dry but to a lesser extent wet) and baghouses, as they are the technology of choice in the power industry. Hybrid systems under development and demonstration are presented. Future control technologies are discussed including pressurized systems such as ceramic and metal filters. Discussions focus on operating principles, designs, and materials of construction. Key words: particulate control, electrostatic precipitators, baghouses, bag filters, ceramic filters, metallic filters, fine particulate matter, PM2.5, PM10

8.1

Introduction

Emissions standards for particulate matter were first introduced in Japan, the US, and Western European nations in the early to mid-1900s. The following decades found many countries also setting standards for particulate emissions including those in Asia, Eastern Europe, Australia, and India. The importance of utilizing coal in an environmentally friendly manner for power generation has led to the introduction or proposal of particulate emissions standards in more than 40 nations (Zhu, 2003). In recent years, there has been increasing concern for control of fine particulate matter and existing particulate emissions standards have progressively become more stringent over the years and the most stringent measures are associated with wealthy countries such as Japan and those in North America and Western Europe (Zhu, 2003). There are a number of technologies for separating particulate matter from 217 © Woodhead Publishing Limited, 2010

218


flue gases generated during coal combustion and these include mechanical/ inertial collection (cyclones/multiclones), fabric filtration (baghouses), electrostatic precipitation, wet scrubbers (mainly venturi scrubbers), and hot-gas filtration. However, for large volumes of flue gas such as those typically found in the current power industry (e.g. using atmospheric pressure systems), along with the requirements of adequate collection efficiency of fine particles (particles with aerodynamic diameters smaller than 2.5 and 10 μm and referred to as PM2.5 and PM10, respectively) and cost-effective particulate removal, electrostatic precipitators (ESPs) and fabric filters are currently the particulate control devices of choice. Cyclones require low capital investment but they exhibit inadequate collection efficiency of fine particles. Wet (venturi) scrubbing requires wastewater treatment systems, has high energy consumption, and is typically not cost effective for large volumes of flue gas. Particulate matter removal via wet scrubbing is performed, however, when combined with sulfur dioxide capture. Hot-gas particulate filtration, which consists of several control concepts used for high-temperature, high-pressure combustion systems (e.g. pressurized fluidized-bed combustion and integrated gasification combined cycle (IGCC)) is in various stages of development from pilot scale to commercial. Consequently, ESPs and fabric filters, which are the primary control technologies for pulverized-coal-fired power plants, will be the focus of this chapter. Future trends will be discussed and include hybrid (i.e. combinations of ESPs and fabric filters) and multipollutant systems under development and demonstration. These near- and mid-term particulate control technologies are performed under atmospheric (or near-atmospheric) pressure and especially focus on fine particulate matter (i.e. PM2.5) because these particles can cause localized plume opacity, visibility impairment, and have been linked to adverse health impacts. These particles can be categorized as primary particulates (pieces of mineral matter and unburned carbon that are entrained in the flue gas along with trace metals), fine acid aerosols (that are created by the reaction of SO3 and water vapor), and secondary particulates (those formed in the atmosphere by chemical reactions involving NOx and SO2). Future power generation technologies are being developed, as discussed in Chapter 3, that are performed under pressure for gains in system efficiency and to address future carbon management legislation. Particulate matter control in pressured systems, which are considered midto longer-term technologies (because these technologies are either not readily deployed, have limited deployment or, in some cases, are not readily accepted at this time), are based on ceramic and metal filter technology and are discussed in section 8.5 as well.


Advanced flue gas dedusting systems and filters

8.2

219

Materials, design, and development for particulate control

Electrostatic precipitators and fabric filters are currently the technologies of choice for coal-fired power generation facilities as they can meet current and pending legislation particulate matter levels while cleaning large volumes of flue gas, achieve very high collection efficiencies, and remove fine particles. When operating properly, ESPs and baghouses can achieve overall collection efficiencies of 99.9% of primary particulates (over 99% control of PM10 and 95% control of PM2.5). The primary particulate matter collection devices used in the power generation industry – ESPs and fabric filters (baghouses) – are discussed in this section. Prior to the 1990s, the technology of choice for large coal-fired power plants was the dry ESP, with fabric filters a distant second. Today the preference is for fabric filters (pulse jet type) for the reasons that will be discussed below (Kitto and Stultz, 2005).

8.3

Electrostatic precipitators (ESPs)

Electrostatic precipitators are the most common industrial devices for particulate control, with an estimated 70% share of the total particulate control market (Zhu, 2003). Particulate and aerosol collection by electrostatic precipitation is based on the mutual attraction between particles of one electrical charge and a collection electrode of opposite polarity. The advantages of this technology are the ability to handle large gas volumes (ESPs have been built for volumetric flow rates up to 113 270 m3/min (4 000 000 ft3/min)), achieve high collection efficiencies (which vary from 99 to 99.9%), maintain low pressure drops (0.1–0.5 in of water column), collect fine particles (0.5–200 μm), and operate at high gas temperatures (gas temperatures up to 6508C (12008F)). In addition, the energy expended in separating particles from the gas stream acts solely on the particles and not on the gas stream. Figure 8.1 is a generalized schematic diagram of an ESP (modified from Kitto and Stultz (2005) and Soud and Mitchell (1997)). Dry ESPs have been used in the control of particulate emissions from coal-fired boilers used for steam generation for about 60 years (Davis, 2000). Initially, all ESPs were installed downstream of the air preheaters at temperatures of 130–1808C (270–3508F), and are referred to as cold-side ESPs. ESPs have been installed upstream of air preheaters where the temperature is in the range 315–4008C (600–7508F) (i.e. hot-side ESPs) as a result of using low-sulfur fuels with lower fly ash resistivity. Wet ESPs (WESPs), a subclass of ESPs, which are discussed separately later, have not historically been used for utility or industrial boiler emissions control when firing coal, oil, or gas (Kitto and Stultz, 2005). However, with the emergence


220


8.1 Generalized schematic diagram of an ESP (modified from Kitto and Stultz (2005) and Soud and Mitchell (1997)).

of more stringent emissions control requirements in reducing both fine particles and overall emissions, use of non-traditional fuels, and the interactions of other emissions control equipment, there has been renewed interest in the use of WESPs to control selected emissions, especially sulfuric acid mist and fine dry particles.

8.3.1 Operating principles There are several basic geometries used in the design of ESPs, but the common design used in the power generation industry is the plate-and-wire configuration. In this design, the ESP consists of a large hopper-bottomed box containing rows of plates, forming passages through which the flue gas flows. Centrally located in each passage are electrodes energized with highvoltage (45–70 kV), negative-polarity, direct current (d.c.) provided by a transformer rectifier set (Elliot, 1989). Power supplied by the transformer rectifier is usually in the range 0.2–0.6 W/m3 of flue gas treated. The flow is usually horizontal and the passageways are typically 150–200 mm (8–10 in) wide. The height of a plate varies from 5.5 to 12.2 m (18 to 40 ft) with a length of 7.6 to 9.1 m (25 to 30 ft). The ESP is designed to reduce the flue gas flow from 15.2–18.3 m/s (50–60 ft/s) to less than 3.3 m/s (10 ft/s) as it enters the ESP, so the particles can be effectively collected. Experience has shown that flow velocities of 0.9–1.5 m/s (3–5 ft/s) are optimum in order to avoid ash re-entrainment (Davis, 2000). Electrostatic precipitation consists of three steps: (i) charging the particles to be collected via a high-voltage electric discharge; (ii) collecting the



221

8.2 Basic concept of charging and collecting particles in an ESP (modified from Soud and Mitchell (1997)).

particles on the surface of an oppositely charged collection surface; and (iii) cleaning the collection surface. These are illustrated in Fig. 8.2 (modified from Soud and Mitchell (1997)).

8.3.2 Particle charging The electrodes discharge electrons into the flue gas stream, ionizing the gas molecules. These gas molecules, with electrons attached, form negative ions. The gas is heavily ionized in the vicinity of the electrodes resulting in a visible blue corona effect. The fine particles are then charged through collisions with the negatively-charged gas ions resulting in the particles becoming negatively charged. The amount of charge that can be placed on a particle is proportional to the surface area of the particle, with the larger particles requiring less energy for charging and being more readily precipitated than the smaller ones. The charging mechanism for particles greater than 2 μm in diameter is by field charging, which is collision between the corona ions and the particles (Zhu, 2003). As particle size decreases, the charging mechanism changes to diffusion charging, that is as the ions pass near the particles they induce a charge on them. For extremely small particles, below 0.1 μm, Brownian motion assists in both charging and migration, which results in improved capture of smaller particles. Dry ESPs typically have a minimum collection efficiency with particles in the 0.5– 1.0 μm size range.


222


8.3.3 Particle collection Under the large electrostatic force, the negatively charged ash particles migrate out of the gas stream toward the grounded plates, that is the collecting electrodes, where they collect forming an ash layer. The speed at which the migration of the ash particles takes place is known as the migration or drift velocity. This velocity depends upon the electrical force on the charged particle as well as the drag force developed as the particle attempts to move perpendicular to the main gas flow toward the collecting electrode (Wark et al., 1998). The drift velocity, w, is defined as w¼

2:95 1012 pEc Ep dp Kc mg

½8:1

where w is in metres per second, p is the dielectric constant for the particles (which typically lies between 1.50 and 2.40), Ec is the strength of the charging field (V/m), Ep is the collecting field strength (V/m), dp is the particle diameter (μm), Kc is the Cunningham correction factor for particles with a diameter less than roughly 5 μm (dimensionless), and mg is the gas viscosity (kg/m s). The Cunningham correction factor in equation [8.1] is defined as (Wark, et al., 1998) i 2l h Kc ¼ 1 þ ½8:2 1:257 þ 0:400eð0:55dp =lÞ dp where λ is the mean free path of the molecules in the gas phase. This quantity is given by l¼

mg 0:499g um

½8:3

where um is the mean molecular speed (m/s) and pg is the gas density (kg/m3). From the kinetic theory of gases, um is given by 8Ru T um ¼ ½8:4 M where M is the molecular weight of the gas, T is temperature ( K), and Ru is the universal gas constant (8.31 103 m2/s2 mole 8K). The drift velocity is used to determine collection efficiency using the Deutsch–Anderson equation Z ¼ 1 eð Q Þ wA

½8:5

where w is the drift velocity, A is the area of collection electrodes, and Q is



223

the volumetric flow rate. The units of w, A, and Q must be consistent since the factor wA/Q is dimensionless. The ratio, A/Q, is often referred to as the specific collection area (SCA) and is the most fundamental ESP size descriptor (Elliot, 1989). Collection efficiency increases as SCA and w increase. The value of w increases rapidly as the voltage applied to the emitting electrode is increased; however, the voltage cannot be increased above that level at which an electric short circuit, or arc, is formed between the electrode and ground.

8.3.4 Ash removal The collecting plates are periodically cleaned to release the layer into the ash hoppers as an agglomerated mass by a mechanical (rapping) system in a dry ESP or by water washing in the case of a WESP. The hopper system must be adequately designed to minimize ash re-entrainment into the gas stream until the hopper is emptied. The strength of the electric field and ash bonding on the plates, mass gas flow, and the striking energy must be matched to ensure that ash is not re-entrained into the gas stream (Miller and Tillman, 2008). The ideal situation is where the electric field holding the ash layer that is directly adjacent to the plate is of such strength that the strike energy just breaks this bond and gravity dislodges the particulate matter into the ash hopper.

8.3.5 Collection efficiency Fly ash collection will never achieve 100%; however, when multiple fields or bus sections are integrated, the process can approach 100%. By rule of thumb, the inlet bus section will collect 80% of the ash delivered at its face. All fields after the inlet field will collect 70% of the ash (Miller and Tillman, 2008). The efficiencies of multiple field precipitators are illustrated in Table 8.1.

Table 8.1

Precipitator efficiency by the number of fields

Number of fields

Amount of ash collected: %

Amount of ash bypassing field: %

Overall efficiency: %

1 2 3 4 5 6

80.00 14.00 4.20 1.26 0.38 0.11

20.00 6.00 1.80 0.54 0.16 0.05

80.00 94.00 98.20 99.46 99.84 99.95


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8.3.6 Factors that affect ESP performance There are several factors that affect ESP performance and are considered when sizing precipitators. Of these, resisitivity is the most important parameter and is often the source of most malfunctions (Miller and Tillman, 2008). Resisitivity is an inverse measure, in W cm, of a particle’s ability to accept and hold a charge. Lower resistivity indicates improved ability to accept a charge and be collected in an ESP. Resistivity is dependent on the flue gas temperature and chemistry, and the chemical composition of the ash itself. Electrostatic precipitation is most effective in collecting dust in the resistivity range 104–1010 W cm (Wark et al., 1998). In general, resistivities above 1011 W cm are considered to be a problem because the maximum operating field strength is limited by the fly ash resistivity. Back corona, the migration of positive ions generated in the fly ash layer towards the emitting electrodes, which neutralize the negatively-charged particles, will result if the ash resistivity is greater than 1012 W cm. If the fly ash resistivity is below 2 1010 W cm, it is not considered to be a problem because the maximum operating field strength is limited by factors other than resistivity. Figure 8.3 is a curve showing the relationship between temperature and resistivity defined by the sulfur content for a family of coals. Two very important relationships are illustrated in this graph. The first is the impact that chemistry has on collection. As sulfur in the coal increases (and hence

8.3 The effect of temperature on resistivity based on coal sulfur content.



225

SO2/SO3 concentration in the flue gas increases), the resisitivity decreases. The second impact is the shape of the curve as temperature changes. The fly ash collectability can be affected by temperature swings in the flue gas. An example of the effect of ash composition on fly ash resistivity is shown in Fig. 8.4 where resistivity is plotted as a function of temperature for four US lignite (two from North Dakota) and sub-bituminous samples (two from the Powder River Basin) (modified from Miller (2005)). The differences in fly ash resisitivity can be attributed to variations in ash composition. The low-resisitivity fly ashes were produced from coals that contained higher levels of sodium in the coal ash. Higher sodium levels result in lower resistivity. Similarly, higher concentrations of iron also lower resisitvity. Higher levels of calcium and magnesium, however, have the opposite effect on resistivity. Particle size also affects ESP performance. An ESP is less efficient for smaller particles, that is less than 2 μm, than for larger ones. Therefore, ESP applications with a high percentage of particles less than 2 μm will require more collection surface and/or lower gas velocities. The dome-shaped curves shown in Figs 8.3 and 8.4 are typical of fly ashes. The shape of the curves is due to a change in the mechanism of conduction through the bulk layer of particles as the temperature is varied (Wark et al., 1998). The predominant mechanism below 1508C (3008F) is surface conduction, where the electric charges are carried in a surface film adsorbed on the particle. As the temperature is increased above 1508C (3008F), the phenomenon of adsorption becomes less effective and the predominant mechanism is volume or intrinsic conduction. Volume conduction involves passage of electric charge through the particles. The three primary mechanical deficiencies in operating units are gas sneakage, fly ash reentrainment, and flue gas distribution (Elliot, 1989). Flue gas sneakage, that is flue gas that is by-passing the effective region of the ESP, increases the outlet dust loading. Re-entrainment occurs when individual dust particles are not collected in the hoppers but are caught up in the gas stream, increasing the dust loading to the ESP and resulting in higher outlet dust loadings. Non-uniform flue gas distribution throughout the entire cross-section of the ESP decreases the collection ability of the unit. There are many additional factors that can affect the performance of an ESP, including the quality and type of fuel. Changes in coal and ash composition, grindability, and the burner/boiler system are important. Fly ash resistivity increases with decreasing sulfur content, an issue that must be considered when switching to lower-sulfur coals. Moisture content and ash composition affect resistivity, as discussed earlier. Changes in coal grindability can affect pulverizer performance by altering particle size distribution, which in turn can affect combustion performance and ESP


226


8.4 Illustration of the effect of ash composition on fly ash resistivity for coals from the same geographical location (modified from Miller (2005)).



227

performance. Modifications to the boiler system can affect temperatures or combustion performance and thereby affect ESP performance.

8.3.7 Performance enhancement A change in fuel, a boiler upgrade, a change in emissions regulation, or deterioration in performance may require a precipitator performance upgrade. Enhancement techniques include flue gas conditioning, additional collection surface, improved/modified gas flow distribution, additional sections, wide plate spacing, additional rapping, control upgrades, internal replacements, or modified energization techniques (Elliot, 1989; Kitto and Stultz, 2005; Miller and Tillman, 2008). These enhancements are primarily required owing to difficulties in collecting high-resistivity fly ash and fine particles. A primary approach to achieving electrical resistivities in the desired range is the addition of conditioning agents to the flue gas stream. This technique is applied commercially to both hot-side and cold-side ESPs. Conditioning modifies the electrical resistivity of the fly ash and/or its physical characteristic by changing the surface electrical conductivity of the dust layer deposited on the collecting plates, increasing the space charge on the gas between the electrodes, and/or increasing dust cohesiveness to enlarge particles and reduce rapping re-entrainment losses (Elliot, 1989). The most common conditioning agents are sulfur trioxide (SO3), ammonia (NH3), compounds related to them, and sodium compounds. Sulfur trioxide is most widely applied for cold-side ESPs, where as sodium compounds are used for hot-side ESPs. Results vary between coal and system, but the injection of 10–20 ppm of SO3 can reduce the resisitivity to a value that will permit good collection efficiencies. In select cases, SO3 injection of 30–40 ppm has resulted in reductions of fly ash resisitivity of two to three orders of magnitude (e.g. from 1011 to ≈108 W cm) (Wark et al., 1998). Disadvantages of SO3 injection systems include the possibility of plume color degradation. Disadvantages for sodium compounds are the potential problems with increased deposition and interference from certain fuel constituents, which affects the economics of the injection. Combined SO3–NH3 conditioning is used, with the SO3 adjusting the resisitivity downward while the NH3 modifies the space–charge effect, improves agglomeration, and reduces rapping re-entrainment losses (Elliot, 1989).

8.3.8 Wet ESPs Dry ESPs have been successfully used for many years in utility applications for coarse and fine particulate removal. Dry ESPs can achieve 99+% collection efficiency for particles 1–10 μm in size. However, dry ESPs: (i)


228


cannot remove toxic gases and vapors that are in a vapor state at 2048C (4008F); (ii) cannot efficiently collect very small fly ash particles; (iii) cannot handle moist or sticky particulate that would stick to the collection surface; (iv) require much space for multiple fields due to re-entrainment of particles; and (v) rely on mechanical collection methods to clean the plates, which require maintenance and periodic shutdowns (Buckley and Ray, 2003). Wet electrostatic precipitators (WESPs) address these issues and are a viable technology to collect finer particulates than conventional technology, while also collecting aerosols. The use of WESPs has mainly been in small, industrial-type settings, as opposed to utility power plants, where they are used to control acid mists, submicron particulate (as small as 0.01 μm with 99.9% removal), mercury, metals, and dioxins/furans as the final polishing device within a multipollutant control system (Buckley and Ray, 2003). However, with proposed changes in the current emissions regulations that require the control of a multitude of pollutants, which comprise submicron particles, mists, and metals, there has been an increased interest in WESPs. When integrated with upstream air pollution control equipment, such as a selective catalytic reactor (SCR), dry ESP, and wet scrubber, multiple pollutants can be removed with the WESP acting as the final polishing device. Wet ESPs operate in the same three-step process as dry ESPs – charging, collecting, and cleaning the particles from the collecting electrode (Altman et al., 2001). However, cleaning of the collecting electrode is performed by washing the collection surface with liquid, rather than by mechanically rapping the collection plates. WESPs continually wet the collection surface and create a dilute slurry that flows down the collecting wall to a recycle tank, never allowing a layer of particulate cake to build up (Altman et al., 2001). As a result, captured particulate is never re-entrained. Also, when firing low-sulfur coal, which produces a high-resisitivity dust, the electrical field does not deteriorate and power levels within a WESP can be dramatically higher than in a dry ESP – 2000 W/28.3 std m3/min (1000 scfm) versus 100–500 W/28.3 std m3/min (1000 scfm), respectively.

8.3.9 Materials of construction Materials for the dry precipitator enclosure and internals are normally carbon steel, ASTM A-36 or equivalent, because gas constituents are noncorrosive at normal operating gas and casing temperatures (Kitto and Stultz, 2005). As in any industry, special conditions may warrant an upgrade in some component materials. In the WESP, the moist corrosive atmosphere requires careful selection of material in critical areas. Materials that have been used include 6% Mo stainless steel, 304 L stainless steel, and alloy 904 L stainless steel (Staehle et al., 2003).



8.4

229

Fabric filters

Historically, ESPs have been the principal control technology for fly ash emissions in the electric power industry. However, as particulate control regulations have become more stringent, ESPs have become larger and more expensive. Also, increased use of low-sulfur coal has resulted in the formation of fly ash with higher electric resistivity that is more difficult to collect. Consequently, ESP size and cost have increased to maintain high collection efficiency (Bustard et al., 1988). As a result, interest in fabric filters has increased. However, prior to about 1970, the development and use of fabric filters was limited because of two crucial factors: material availability and bag chemical resistance. The availability of materials limited installations to temperatures below 1208C (2508F), and the chemical resistance characteristics of the bags reduced fabric filtration. As advancements were made, the interest in fabric filters increased as a result of successful installations on large coal-fired boilers that proved to have good operation and high collection efficiencies of particulate matter. Fabric filter technology has an extremely high collection efficiency (i.e. 99.9–99.99+%), is capable of filtering large volumes of flue gas, and its size and efficiency are relatively independent of the type of coal burned (Bustard et al., 1988). Fabric filters remove particles from a gas stream by passing them through a porous fabric. Particles form a porous cake on the surface of the fabric and it is this cake that does the filtration. Fabric filter systems are referred to as ‘baghouses’ since the fabric is usually configured in cylindrical bags. These baghouses are typically located downstream of the air preheater and operate in the temperature range 120–1808C (250–3608F). Advantages of fabric filters include: high collection efficiency over a broad range of particle sizes; flexibility in design provided by the availability of various cleaning methods and filter media; wide range of volumetric capacities in a single installation; reasonable operating pressure drops and power requirements; and ability to handle a variety of solid materials (Wark et al., 1998). Disadvantages of baghouses include large footprints whereby space factors may prohibit consideration of baghouses; possibility of an explosion or fires if sparks are present in the vicinity of a baghouse; and hydroscopic materials usually cannot be handled, owing to cloth cleaning problems.

8.4.1 Operating principles Baghouses remove particles from the flue gas within compartments arranged in parallel flow paths, with each compartment containing several hundred large, tube-shaped filter bags. Figure 8.5 is an example of air flow in a typical pulse-jet baghouse (modified from Mikropul Environmental


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8.5 Generalized schematic diagram of a baghouse (modified from Mikropul Environmental Systems (1989)).

Systems, 1989). A baghouse on a 500 MW coal-fired unit may be required to handle in excess of 0.06 Mm3/min (2 million ft3/min) of flue gas at temperatures of 120–1808C (250–3508F) and will consist of many compart-



231

ments. From an inlet manifold, the dirty flue gas, with typical dust loadings from 0.1 to 10 grains/ft3 of gas (0.23–23 gs/m3), enters hopper inlet ducts that route it into individual compartment hoppers. From each hopper, the gas flows upward through the bags where the fly ash is deposited. The clean gas is drawn into an outlet manifold, which carries it out of the baghouse to an outlet duct. Periodic operation requires shutdown of portions of the baghouse at regular intervals for cleaning. Cleaning is accomplished in a variety of ways, including mechanical vibration or shaking, pulse jets of air, and reverse gas flow. The two fundamental parameters in sizing and operating baghouses are the air-to-cloth (A/C) ratio and pressure drop across the filters. Other important factors that affect the performance of the fabric filter include the flue gas temperature, dew point, and moisture content, and particle size distribution and composition of the fly ash (Soud, 1995). The A/C ratio, which is a fundamental fabric filter descriptor denoting the ratio of the volumetric flue gas flow (m3/min (ft3/min)) to the amount of filtering surface area (m2 (ft2)), is reported in units of m/min (ft/min) (Elliot, 1989). For fabric filters, it has been generally observed that the overall collection efficiency is enhanced as the A/C ratio, that is superficial filtration velocity, decreases. Factors to be considered with the A/C ratio include type of filter fabric, type of coal and firing method, fly ash properties, duty cycle of the boiler, inlet fly ash loading, and cleaning method (Soud, 1995). Pressure drop is a measure of the energy required to move the flue gas through the baghouse. Factors affecting pressure drop are boiler type (which influences the fly ash particle size), filtration media, fly ash properties, and flue gas composition (Soud, 1995). As the filter cake accumulates on the supporting fabric, the removal efficiency typically increases; however, the resistance to flow also increases. For a clean filter cloth, the pressure drop is about 0.12 kPa (0.5 inches water column (WC)) and the removal efficiency is low. After sufficient filter cake build-up, the pressure drop can increase to 0.50–0.75 kPa (2–3 ins WC) with the removal efficiency 99+% (Wark et al., 1998). When the pressure drop reaches 1.25–1.49 kPa (5–6 ins WC), it is usually necessary to clean the filters. The pressure drop for both the cleaned filter and the dust cake, ΔPT , may be represented by Darcy’s equation DPT ¼ DPR þ DPC ¼

mg xR V mg KC V þ KR KC

½8:6

where ΔPR is the conditioned residual pressure drop, ΔPC is the dust cake pressure drop, KR and KC are the filter and dust cake permeabilities, respectively, V is the superficial velocity, mg is the gas viscosity, and xR and


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xC are the filter and dust cake thicknesses, respectively. The permeabilities KR and KC are difficult quantities to predict with direct measurements since they are functions of the properties of the filter and dust such as porosity, pore size distribution, and particle size distribution. Therefore, in practice ΔPR is usually measured after the bags are cleaned and ΔPC is determined using the equation DPC ¼ K2 Ci V2 t

½8:7

where Ci is the dust loading and, along with V, is assumed constant during the filtration cycle, t is the filtration time, and K2, the dust resistance coefficient is estimated from ! 0:6 mg 0:00304 2600 V K2 ¼ ½8:8 p 0:0152 ðdg;mass Þ1:1 mg;70 =F where dg is the geometric mass median diameter (m), mg is the gas viscosity (kg/m s), ρp is the particle density (kg/m3), and V is the superficial velocity (m/s).

8.4.2 Specific designs There are three basic types of baghouses – reverse-gas, shake-deflate, and pulse-jet. They are distinguished by the cleaning mechanisms and by their A/ C ratio. The two most common baghouse designs are the reverse-gas and pulse-jet types. Reverse-gas fabric filters are generally the most conservative design of the fabric filter types. The filter typically operates at low A/C ratio ranging from 0.46 to 1.07 m/min (1.5–3.5 ft/min) (Soud, 1995; Wark et al., 1998). Fly ash collection is on the inside of the bags as the flue gas flow is from the inside of the bags to the outside. Reverse-gas baghouses use off-line cleaning where compartments are isolated and cleaning air is passed from the outside of the bags to the inside, causing the bags partially to collapse to release the collected ash. The dislodged ash falls into the hopper. A simplified schematic diagram showing the cleaning cycle is given in Fig. 8.6 (modified from Soud and Mitchell (1997)). Shake-deflate baghouses are another low A/C type system (0.61–1.22 m/ min (2–4 ft/min)) and they collect dust on the inside of the bags, similar to the reverse-gas systems (Wark et al., 1998). With shake-deflate cleaning, a small quantity of filtered gas is forced backward through the compartment being cleaned, which is done off-line. The reversed filtered gas relaxes the bags but does not completely collapse them. As the gas is flowing, or immediately after it is shut off, the tops of the bags are mechanically shaken



233

8.6 Simplified schematic diagrams of baghouse cleaning mechanisms (modified from Soud and Mitchell (1997)): (a) reverse-gas; (b) pulse-jet; (c) shake-deflate.

for 5–20 s at frequencies ranging from 1 to 4 Hz and at amplitudes of 19–50 mm (0.75–2 inches) (Bustard et al., 1988). A simplified schematic diagram showing the cleaning cycle is illustrated in Fig. 8.6. In pulse-jet fabric filters, the flue gas flow is from the outside of the bag inward. The A/C ratio is higher than reverse-air units and is typically 0.91–


234


1.22 m/min (3–4 ft/min) allowing for a more compact installation, but the ratio can vary from 0.61 to 1.52 m/min (2–5 ft/min) (Wark et al., 1998). Cleaning is performed with a high-pressure burst of air into the open end of the bag. Pulse-jet systems require metal cages on the inside of the bags to prevent bag collapse. Bag cleaning can be performed on-line by pulsing selected bags while the remaining bags continue to filter the flue gas. A simplified schematic diagram showing the cleaning cycle is given in Fig. 8.6.

8.4.3 Performance enhancement The most recognized method to enhance fabric filter performance is the application of sonic energy. Virtually all reverse-gas baghouses have included sonic horns (Elliot, 1989). With this method, low-frequency ( 90%), while providing some trim control (20– 50%) of SO2 and other gases in addition to removal of mercury.

8.5.2 Mid- to long-term technologies As a key component in advanced coal-based power applications, such as pressurized fluidized-bed combustion (PFBC) or IGCC plants, hot gas filtration systems protect the downstream gas turbine components from particulate fouling and erosion, cleaning the process gas to meet emissions



239

requirements. In IGCC systems, the hot gas particulate filter must operate in reducing gas conditions (i.e. in the presence of H2, CH4, CO), high system pressure (1.0–2.4 MPa (150–350 psi)) and at operating temperatures usually determined by the method of sulfur removal, that is in bed, external, or by cold gas scrubbing. Typically, these temperatures range around 9508C (16508F) (in bed), 480–6508C (900–12008F) (external) and 260–540 8C (500–10008F) (cold scrubbing). In gasification applications, cold scrubbing of the fuel gas has been demonstrated as effective in cleaning the fuel gas to meet turbine and environmental requirements. However, with this process, plant energy efficiency is reduced, and higher capital costs are incurred. Incorporating a hot particulate filter upstream of the scrubbing unit reduces heat exchanger costs and provides for dry ash handling (partial hot gas cleaning). For bubbling bed PFBC applications, the hot gas filter must operate at temperatures of 8608C (15808F) and system pressures of 1.2 MPa (175 psia).

8.8 Schematic diagram of a hot-gas filtration vessel (modified from Yongue et al. (2007)).


240


8.9 Photograph of the internals of a hot-gas filtration vessel (DOE, 2008b).

For these commercial-scale systems, multiple filter vessels are required. Thus, the filter design should be modular for scaling. A schematic diagram of a filter vessel is shown in Fig. 8.8 (modified from Yongue et al. (2007)) with a photograph of a vessel internals provided in Fig. 8.9 (DOE, 2008b). Ceramic and metal filters are used in many industrial applications including incinerators, metal smelters, chemical processes, oil refining, and mineral processing. Much development work has been directed towards using these filters in advanced power generation. Initially, development work in the late 1980s and 1990s focused on ceramic filters for the high-temperature applications. However, they had a history of breaking due to thermal stresses from thermal transients in the



241

Table 8.3 Examples of materials of composition for various filter media (modified from Pall (2006)) Operating Chloridetemperature bearing

Sulfur-bearing Caustic

10008C

Ceramic

9008C

Hastelloy X

Oxidizing Reducing atmosphere atmosphere

Ceramic

8008C

Hastelloy X Iron aluminide

7508C

Iron aluminide

Iron aluminide

Ceramic

Ceramic

7008C

Hastelloy X

6508C

310SC

Nickel 201 310SC

6008C

310SC Ceramic

5508C

Inconel 600

5008C

C-276

4208C

Inconel 600 316L

3008C

316L

316L

Nickel 200

2508C

Alloy 20

1258C

C-22

Alloy 20

316L

process, which resulted in developers exploring other options. Then when PFBC technology progressed slowly, the interest in using high-temperature ceramic filters in power generation decreased. These issues, coupled with more moderate IGCC temperatures, resulted in industry exhibiting interest in metallic filters for power generation with significant developmental work beginning in the early 1990s (Alvin, 2004). Consequently, metallic filters are becoming the filter of choice for these applications, although ceramics, which exhibit a wider range of corrosion resistance than many of their metallic counterparts, are still the filter of choice for temperatures above 500–6508C (1100–12008F) because of sulfidation attack on most metal filters. Table 8.3 lists some materials of construction for different atmospheres and temperatures (modified from Pall Corporation (2006)).

8.6


Sources of other information include: . .

US Department of Energy National Energy Technology Laboratory website where coal power systems can be found: http://www.netl.doe. gov/ International Energy Agency website: http://www.iea.org


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8.7

References

Altman R, Offen G, Buckley W, and Ray I (2001), ‘Wet electrostatic precipitation demonstrating promise for fine particulate control, part I’, Power Engineering, 105(1), 37–39. Alvin M (2004), Metal filters for pressurized fluid bed combustion (PFBC) applications, final report, DOE/NETL contract no. DE-AC26-98FT40002. Buckley W and Ray I (2003), ‘Application of wet electrostatic precipitation technology in the utility industry for PM2.5 control’, Proceedings of the EPRIDOE-EPA combined power plant air pollution control MEGA symposium. Bustard C, Cushing K, Pontius D, Smith W, and Carr R (1988), Fabric filters for the electric utility industry, Vol. 1: general concepts, Palo Alto, California, Electric Power Research Institute. Caine J and Shah H (2006), ‘Membrane WESP – A lower cost technology to reduce PM2.5, SO3, and Hg+2 emissions, Proceedings of the 2006 environmental control conference. Davis W (ed.) (2000), Air pollution engineering manual, 2nd edition, New York, Wiley. DOE (US Department of Energy) (2001), Advanced hybrid particulate collector fact sheet, Washington, DC, Office of Fossil Energy. DOE (US Department of Energy) (2003), Demonstration of a full-scale retrofit of the advanced hybrid particulate collector (AHPC) collector fact sheet, Washington, DC, Office of Fossil Energy. DOE (US Department of Energy) (2008a), Mercury control projects, topical report number 26, Washington, DC Office of Fossil Energy. DOE (US Department of Energy) (2008b), http://www.netl.doe.gov/technologies/ coalpower/ gasification. Elliot T (ed.) (1989), Standard handbook of powerplant engineering, New York, McGraw-Hill Publishing Company. Gebert R, Rinschler C, Davis D, Leibacher U, Studer P, Eckert W, Swanson W, Endrizzi J, Hrdlicka T, Miller S, Jones M, Zhuang Y, and Collings M (2002), ‘Commercialization of the advanced hybrid filter technology’, Conference on Air quality III: mercury, trace elements, and particulate matter, Grand Forks, North Dakota, University of North Dakota. Kitto J and Stultz S (eds) (2005), Steam, its generation and use, Barberton, Ohio, The Babcock and Wilcox Company. Mikropul Environmental Systems (1989), Mikro-Pulsaire® filtration products, Morris Plains, New Jersey, Mikropul Environmental Systems. Miller B (2005), Coal energy systems, Oxford, Elsevier. Miller B and Tillman D (eds) (2008) Combustion engineering issues for solid fuel systems, Burlington, Massachusetts, Academic Press. Miller R, Harrison W, Prater D, and Chang R (1997), ‘Alabama Power Company E. C. Gaston 272 MW electric steam plant – unit no. 3 enhanced COHPAC I installation’, Proceedings of the EPRI-DOE-EPA combined utility air pollution control symposium: The MEGA symposium, Vol. III: Particulates and air toxics. Pall Corporation (2006), Pall gas solid separation systems, advanced metal and ceramic filter systems for critical gas solid separation processes, New York, Pall Corporation.



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Soud H (1995), Developments in particulate control for coal combustion, London, IEA Coal Research. Soud H and Mitchell S (1997), Particulate control handbook for coal-fired plants, London, IEA Coal Research. Staehle R, Triscori R, Ross G, Kumar K, and Pasternak E (2003), The past, present and future of wet electrostatic precipitators in power plant applications’, Proceedings of the EPRI-DOE-EPA combined power plant air pollution control MEGA symposium. Wark K, Warner C, and Davis W (1998), Air pollution its origin and control, 3rd edition, Menlo Park, California, Addison Welsey Longman, Inc. Yongue R, Guan X, Dahlin R, and Landham E (2007), ‘Update on hot gas filtration testing at the power systems development facility’, 32nd International Technical Conference on Coal utilization and fuel systems, Washington, DC, Coal and Slurry Technology Association. Zhu Q (2003), Developments in particulate control, London, IEA Clean Coal Centre.


9 Advanced sensors for combustion monitoring in power plants: towards smart high-density sensor networks M . Y U and A . K . G U P T A , University of Maryland, USA; M . B R Y D E N , Iowa State University, USA

Abstract: Future advanced combustors and power plants will require a large number of sensors that can provide detailed information for better monitoring and control of the various on-going processes within the system. Traditional sensors are large and expensive for providing comprehensive spatial, temporal, and volume information in a process. There are some inherent barriers to develop new micro- and nano-scale sensors. The use as well as the interpretation of data from a large array of micro- and nano-scale sensors in a power plant operation is another barrier. This chapter addresses various sensor needs, as well as suggesting various sensing strategies. Issues and algorithms that must be considered for the use of a high-density sensor network in future advanced combustors and power plant systems, are also discussed. Key words: sensor networks, micro/nano sensors, power plant monitoring and control, volume distributed combustion process control.

9.1

Introduction

The new generation of advanced power plants are challenged owing to the on-going needs for significantly more efficiency and reducing pollutants emission, including carbon emissions. This requires new equipment design, new plant configurations, and new instrumentation. Future advanced power plants and processes will require a large number of sensors that can provide detailed information on the various on-going processes within the system. These sensors can be of the same type or different types located at different positions in the power plant. With more sensors, one can obtain comprehensive information, which then must be processed on-line to 244 © Woodhead Publishing Limited, 2010

Advanced sensors for combustion monitoring

245

control the process. In contrast, with one or few sensors, not much of the detailed information can be captured in the system. The traditional intrusive and non-intrusive sensors are large and expensive as a means of providing comprehensive spatial, temporal, and volume information in a process. Advances in photonics, micro/nano electronics, materials science, and micro-electromechanical systems (MEMS) have led to dramatic improvements in the design of micro- and nano-scale sensors. A revolution in sensing and control is rapidly approaching. It is expected that in a decade, the sensors will be dramatically smaller, less expensive, capable of surviving harsher, more challenging environments and smarter, if progress matches our past experiences in the case of personal computers. These micro-sensors will be able to provide comprehensive information on the various on-going processes occurring in complex situations. However, there are still some inherent barriers to building micro- and nano-scale sensors. In addition, the use as well as the interpretation of data from a large array of micro-scale and nano-scale sensors in a power plant operation are further barriers. Micro- and nano-scale sensors will be fundamentally different from the currently used sensors in power plants and processes. In a similar way to the current sensors, the micro- or nano-scale sensors will be able to provide detailed information on one location, but because they are inexpensive, it is possible to have many to finely tune and control the process in real time from the volume distributed information. Thus the availability of many inputs will pose the challenge of determining the real conditions and how to use the vast amount of information obtained from the sensors. There are many responses to this coming data flood. A first reaction to this revolution in sensing technology is that more data are good for detailed modeling and model development to evaluate the performance behavior of power plants or processes. However, there are significant challenges in interacting with these micro-sensors and controlling a new generation of power plant. Thus, the coming flood of data will challenge the current datahandling and data-processing capabilities, and change how sensors are used to control power plants and processes. Based on the potential rewards and the significant challenges, it is important to consider research and development efforts for the design and selection of new types of sensors and to develop algorithms and methodologies on how to use them in future devices. Currently, very little is known regarding how to determine the number of sensors that must be used to provide adequate and effective information in a power plant, except that more may be better. Many of the sensors of such types are still under development. Furthermore, it is not known what should be the critical locations for these sensors to provide representative information. Also, it is not known if special features (e.g. multiple functions for a single sensor, on-board processing, and decisionmaking tools) will substantially improve a plant or process performance.


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A starting place to resolve the above questions lies in linking sensors to physics-based models that resolve data on the same length and time scales as the sensors. There are a couple of approaches to accomplish this. One approach could be to compare the inputs from the sensors directly with a physics-based model running in real-time mimicking the plant or process behavior. There are several challenges to this approach. The current highfidelity models are slow and it is not clear how deviations among the data from the many sensors and the model predictions would be handled. Another approach is to have a hierarchical sensor network including leader sensor arrays and micro-scale and nano-scale sensors as swarms or small groups rather than as individual sensors that work together to handle discrete tasks in the sensing and control network. This can be thought of as a holistic or cellular approach to sensors and control. Just as there are many cells in the human body that perform important functions but are not individually directed by the brain, these sensors will need to perform their tasks without continuous direct intervention and reporting. To accomplish this, interactions for these sensors will need to be based on self-organization of complex adaptive systems with limited external direction. In this chapter, efforts have been focused on developing a new strategy for a high-density sensor network as well as on developing the potential methodologies that can be used so that the network can provide some detailed insights into the combustion, power plant or process operation for further technology advancement. Built upon current progress,1–3 the various needs for sensors, their relative positions within, at or around the combustor walls or plants, as well the different issues and algorithms considered for use of high-density sensor networks in advanced combustors and power plant systems are discussed.

9.2

Combustion behavior

The combustion behavior is very complex in almost all practical combustion and power plant systems. The combustor performance is dictated by many functions that a process must incorporate and also relies on the outcome of many on-going complex processes in the system. In Fig. 9.1, an experimental combustion test rig is used to examine combustion instability that incorporates pressure waves to affect the combustor performance inside the combustion zone and on into the combustion tunnel. Clearly if one or two sensors are used in the combustion zone or the combustion tunnel, their numerical values will be erroneous because the local value of a given parameter will not reveal the actual representative behavior that occurs in the combustor. Thus, when considering a practical combustion system, there are complex challenges in determining local flow, pressure, chemical



247

9.1 An experimental combustor with various modes of pressure waves inside the tube.


248


composition and thermal signatures, and their interactions to seek optimum performance of the system.

9.3

Sensor considerations

The combustor facility must be able to operate over a wide range of conditions for the different sensors under consideration. To control the operation performance effectively, the main problem lies in the determination of the actual conditions within the combustor. Sensors are critical elements for combustion control and combustion monitoring in order to achieve enhanced efficiency and robust performance of the combustion system.

9.3.1 State-of-the-art sensors for combustion monitoring Optical absorption and emission sensors Diode-laser-based-absorption sensors have been well demonstrated for insitu measurements in the flame region or in the exhaust gases of major combustion species, such as water (H2O), carbon dioxide (CO2), and oxygen (O2), gas temperature, velocity, and pressure.4,5 The light is provided by diode lasers and the detection system includes optical isolators, fibers, and photodetectors. Taking advantage of fiber components for wavelength division multiplexing, multiple lasers may be combined into common signal and reference fibers. However, weak absorption strength in the visible-nearinfrared (IR) range requires advanced detection schemes, such as frequency or wavelength modulation and balanced ratiometric detection. Also, the absorption database in near-IR is incomplete, especially for CO2, in particular under high-temperature and high-pressure conditions. Furthermore, flow turbulence or mechanical vibrations can introduce instabilities in the transmitted radiation and this can degrade the sensor performance. The light emitted by the flame can also be used to monitor and control the combustion. In this case, information can be gathered from ultraviolet (UV) to IR wavelengths to detect combustion products and temperature. The basic light emission processes, which include chemiluminescence, black body emission, and IR emission, have been demonstrated.4,5 However, the method allows only line-of-sight detection and provides mainly qualitative information with little spatial resolution, so that volume distributed information is not obtained. This information is critical for seeking local and global performance.



249

Solid state gas sensors Gas species monitoring is mainly achieved with semiconductor sensors.4 These probes use a semiconducting material to detect a particular species. Materials employed are mainly metal oxides, such as zirconium, titanium, and tin oxides doped with other oxides. The corresponding sensors are often designated as ceramic gas sensors. The principle of these sensors relies on the change of the semiconductor resistance or change of voltage or current across the semiconductor with respect to the presence of the probed species. Solid state gas sensors provide useful information concerning the combustion process, but they have some disadvantages. Gas sensors are operated downstream of the process, which induces a time lag between combustion and the corresponding probe measurements. This delay affects the control algorithm stability and design. Also, these sensors have a slow time response and only provide global information about combustion process. Thus, they cannot be used to monitor transient properties. It is important to point out that both the spatial and temporal resolutions are essential for combustion control. The performance parameters need to be measured in terms of global emissions of the combustion process. In this aspect, the current optical sensors based on line-of-sight methods might lead to low accuracy for evaluating highly non-homogenous flow. In this case, solid state gas sensors exposed to combustion products in the exhaust stream need to be used to evaluate the global performance. However, owing to the time lag of the gas transport, these sensors cannot provide real-time information to provide enough temporal resolution for the desired combustion control. Therefore, as the revolution in sensing and control is rapidly progressing, it is timely to explore high-density, high-performance sensors that can fulfill the requirements of the combustion process of an advanced power plant with zero or near-zero emissions and ultimate high efficiency.

9.3.2 Exploration of novel micro-scale and nano-scale sensors State observation and performance estimation are central issues in combustion control. Current sensors can barely provide integral information of the entire combustor with adequate precision, high spatial resolution, and bandwidth. Novel micro-scale and nano-scale sensors with improved performance are rapidly developing and starting to play more important roles in many applications, so it is expected that they will also have greater impact on combustion process monitoring, as fuels and energy continue to be of increasing importance. The high-density sensor networks envisioned for power plants involve a


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diverse variety of heterogeneous sensors, including novel micro-scale and nano-scale sensors for pressure, flow, and temperature, and various gas species concentration measurements. The heterogeneous sensor system can provide both complementary and competitive information about a combustion system. Complementary information refers to the measurements of different characteristics of the combustion process, whereas competitive information refers to the measurements of the same characteristic but from different sensor units. Such a heterogeneous sensor system can provide a more reliable view and a higher confidence level of the operational status of advanced combustion unit and power plant system. To realize an effective, high-density, heterogeneous sensor system, the following two fundamental questions need to be answered: (i) what are the desired parameters to be measured and (ii) what types of sensors need to be used? The first question has been addressed in the literature.6–10 Some of these parameters include fuel concentration, fuel-to-air ratio, temperature, pressure, flow dynamics and residual gas concentration.6 The hostile conditions prevailing in combustors mean that the selected sensors should be able to withstand exposure to such an environment. In addition, the selection of the size of the sensor needs to be based on the spatial variations in the flow structure and the sensors needs to provide timely responses to monitor relatively fast transient processes. In the following sections, some possible sensors are discussed to shed some light on the second question. Fiber optic sensors Fiber optic sensors have been proven to be successful for measurements in harsh environments;11–13 these sensors possess the advantages of light weight and high sensitivity, they are not susceptible to electromagnetic interference (EMI), they have remote sensing capabilities, and are multiplexible.14 Many of these sensors are made intrinsically within the optical fibers, and thus the diameter sizes of these sensors are on the order of microscale.15–21 Fiber optic sensors have been demonstrated to provide measurement of temperature, pressure, gas concentration and other key parameters to monitor details of the combustion process.15–17 Among various kinds of fiber optic sensors, fiber Bragg grating (FBG) sensors are good candidates for combustion process monitoring. A fiber optic Bragg grating sensor consists of an optical fiber with a periodic perturbation of the refractive index at the core of the fiber. For a wellwritten fiber optic Bragg grating sensor, the reflection (and transmission) characteristics of the fiber include a reflection peak at the Bragg wavelength (and a transmission dip at the same wavelength). Owing to the physical relationship between the optical properties of the fiber and an applied strain or temperature field, these sensors are appealing for strain and temperature



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sensing. The relationship describing the shift in the Bragg wavelength due to the applied temperature and strain fields can be expressed in terms of a linear equation. The coefficients in this equation may be obtained as Pockel constants.18 From the earliest stage of their development, fiber Bragg gratings have been considered as excellent sensor elements, suitable for measuring static and dynamic pressure fields. They also offer excellent multiplexing capabilities, which is definitely a good feature for a highdensity sensor network. However, in hostile combustion environments, there are physical challenges associated with temperature that must be overcome so that they can be used over a prolonged time. Another type of fiber optical sensor that can possibly be used in a combusion environment is the Fabry–Perot sensor. A Fabry–Perot cavity formed between two fiber end faces or between a fiber tip and a diaphragm mirror is a good solution for temperature and pressure sensing, but at the expense of spatial resolution. These sensors are typically more sensitive than FBG sensors. For a highly noisy combustion process, these sensors are expected to provide better performance for pressure sensing. Nano-scale gas sensors Recently, many different nano-scale structures have been proven to have gas sensing capabilities.19,20 By taking advantage of these nano-scale sensor techniques, distributed semi-conducting nano-scale sensors can be developed to measure the concentration of O2, carbon monoxide (CO), and H2O via the conductance readings from each sensor. Although these species are not adequate for seeking details on the combustion process, they do provide some insights on the combustion process. A challenge in deploying a large number of nano-scale sensors is how to read the sensor data and access each sensor.

9.4

Sensor response

To determine information on quantifying the number and location of sensors that adequately describe the exact performance of a practical combustion system is not trivial. The approach taken here is to tackle this challenge by initially selecting the available sensor(s) that can be used to describe the fate of on-going phenomena inside a practical combustor, and then provide information of the fate of combustor performance using information from single and multiple sensors. Acoustic pressure, including that of combustion noise, has been chosen as the initial representative signature parameter. To achieve fundamental understanding of the influence of the sensor location on the sensor readings, acoustic measurements have


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9.2 Schematic diagram of the University of Maryland (UMD) test combustor and (b) detailed view of the UMD test stand.

been carried out at different vertical locations and radial locations immediately outside a test combustor. The University of Maryland (UMD) 50 kW premixed test combustor, shown in Figs 9.2a and 9.2b, features many of the key characteristics associated with practical combustors and is used here for the experimental test program. The combustor possesses several of the key elements that are of critical importance to simulate the behavior of many practical combustion systems used in the power industry. The combustion chamber is 210 mm long and 55 mm inside diameter. A quartz tube, located downstream of the combustor, provides full optical access to the combustor region. The combustion in these tests occurred at atmospheric pressure under semi-confined condition. The premixed condition was achieved by injecting methane fuel 100 mm upstream of the combustor inlet in order to assure good mixing between the fuel and air. The flame was stabilized using six swirl vanes, which could be given any desired swirl strength using 30, 45, or 608 swirl vane angle to the main flow direction. Initial efforts involved using a single sensor to determine the extent of spatial variations at different positions downstream of the combustor, as well as its angular variation at any given axial position downstream from the flame-anchoring location in the combustor. Sound pressure measurements were measured using a piezoelectric microphone sensor coupled to a spectrum analyzer. The analyzer recorded the signal from the microphone and performed fast Fourier transform (FFT) on the signal to convert to the



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frequency domain. The accuracy of the system was ± 1.5 dB with frequency discrimination of ± 1%. The frequency range was measured from 20 to 20 000 Hz. The sound spectrum analysis was averaged over 10 s to obtain a mean value of the results. The goal here was to assure that there were indeed spatial and temporal variations in sound pressure levels around the combustor. A traversing mechanism was assembled to allow the microphone to be positioned at any desired axial and/or angular location relative to the fixed combustor. The arrangement provided 0.01 in (0.25 mm) vertical resolution and 18 angular resolution. The acoustic waves generated from the combustor mainly lie in the frequency range 200 Hz–1 kHz. Low frequencies are associated with the combustion roar (200–500 Hz) while the higher frequencies are associated with some modes of acoustic coupling, including the standing waves in the flow ducts. In order to determine how the combustion-generated acoustic waves are related to the microphone’s vertical location variation, the focus is initially on the near-field acoustic signatures downstream from the combustor exit. The vertical location of the microphone was therefore limited to within 1 in (i.e. z 1 may occur in situations where stronger monitoring is necessary, such as locations with large spatial or temporal gradient. This also occurs when multiple sensors are required to detect an event. Enforcing k ≥ 2 is also necessary for fault-tolerant purposes. A fundamental question is how many sensors are enough. This question should be addressed by using an available combustion model that can provide information on the condition of each zone in the combustor. The principle here is that for certain critical locations, redundancy is necessary and thus k > 1 needs to be satisfied. Ideally, based on the combustion model prediction, the targeted coverage level of each cell in the combustor can be determined. The second fundamental question to be addressed is how one can carry out effective sensor placement to realize the targeted coverage level. This is a somewhat more difficult problem. There are several attempts to solve this problem with graphic solution for some ideal geometry region. The coverage algorithms developed by Li and Yu21 can be used here to determine whether a sensor network is k-covered. The solution can be easily translated to a distributed algorithm where each sensor only needs to collect local information to make its decision. Instead of determining the coverage of each location, the approach tries to look at how the perimeter of each sensor’s sensing range is covered, thus leading to an efficient polynomial time algorithm. As long as the perimeters of sensors are sufficiently covered, the whole area is sufficiently covered. A difficult problem of sensor coverage and placement in a three-dimensional area of a combustor will now be tackled.

9.6

Sensor information processing

9.6.1 Computational sensor calibration model The first step here will be to use a computational sensor calibration model to calibrate simultaneously all of the sensors used in the distributed sensor system. Usually, raw sensor output data are imperfect. Such calibrations



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will ‘remove’ some errors embedded in the sensor output and provide more accurate measurements. The basic idea is to provide accurate estimates of ‘true’ parameter values from the sensor outputs. Thus the initial goal is to find a good mapping from raw reading of the sensors to determine their magnitude that will assist in control algorithm development procedure between the sensor inputs and output units. In order to achieve this, with a given known set of sensor input–output data points (a training sample), a statistical multi-dimensional function can been ‘trained’ that renders optimal estimates of sensor inputs according to some performance criteria, for example, maximum likelihood (ML) or minimum mean square error (MMSE). The trained model can then be applied to future output signals from the sensor and provide reliable estimated sensor input. As a result, the computational calibration model enables the sensors to endure some adverse effects in the face of uncertainties, non-linearities and cross-talk between sensors.

9.6.2 Data aggregation With readings from each group of the localized sensors in the distributed network sensor system, preliminary data processing must first be carried out; for example, filtering and aggregating, to derive ‘information’ from raw readings. Then, the problem must be solved of how the usefulness may be determined of each kind of information extracted in order to achieve the desired parameters in combustion process control for each cell (sensor group). To solve this problem, in general, one needs to be equipped with some model that renders the dependence relationship between the desired parameters and the sensor readings. With such models, some information value of the metrics can be derived, from which different kinds of information can be compared and the most needed information then subsequently transported. For example, Bayesian belief networks models (which can be interpreted as generalizations of hidden Markov models) capture well the dependency structure between various kinds of propositions; notions from information theory, such as information entropy and mutual information, can be exploited to help determine information value. With such information, different kinds of sensor readings will play different roles and will be treated differently for achieving the desired parameters.

9.7

Conclusions

The sample results obtained from a practical combustor using a single sensor have shown that the combustor possesses significant spatial variation. A single sensor is inadequate to provide detailed information from the combustor, in particular when there are large-scale temporal and


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spatial variations. The peak signal is located downstream of the combustor and has been found to depend on geometry and operational parameters. The results clearly identify the need for a multi-sensor network placed around the combustor for seeking detailed information that can allow for better control to achieve higher efficiency and improved performance. A smart sensor network framework for advanced combustion systems in future power plants has been presented, which is aimed at providing a detailed database for future code developments and model validation. A systematic development procedure has been outlined here to determine the sensor type development with multi-function capability, as well as the future means to process the large body of data. The specific focus was on spatial and temporal resolution of the various parameters at all regions of the combustion zone, including the upstream region of the combustion zone, the combustion zone itself and the post-combustion zone. The envisioned sensor network includes a large number of heterogeneous nano-scale or micro-scale sensors, organized by a multi-functional on-chip sensor platform. Optical sensors, such as fiber optic sensors, can perform an important role for online monitoring of the detailed processes. The manner in which a hierarchical sensor network can be realized has also been presented.

9.8

Acknowledgements

This research is supported by the US Department of Energy (DoE) and is gratefully acknowledged. The authors would also like to thank Bob Romanasky and Susan Maley for their help and support.

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3 4 5 6

References Yu M., Bryden K. and Gupta A. K., ‘Developing a program to examine the application of high density sensor networks for power plant application’, The 31st International Technical Conference on Coal utilization and fuel systems, May 2006. Yu M., Bryden K. and Gupta A. K., ‘Sensor response and their interpretation in a practical combustor’, The 32nd International Technical Conference on Coal utilization and fuel systems, June 2007. Yu M., Bryden K. and Gupta A. K., ‘Sensor response and sensor network development for practical combustors’, ICCCN 2007, Hawaii, August 2007. Docquier N. and Candel S., Combustion control and sensors: a review’, Progr. Energy Combust. Sci., 2002, 28, 107–150. Allen M. G., ‘Diode laser absorption sensors for gas-dynamic and combustion flows’, Measmt Sci. Technol., 1998, 9, 545–562. Gupta A. K. and Lilley D. G., Flowfield modeling and diagnostics, Tunbridge Wells, Kent, Abacus Press, 1985.


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Tsuji H., Gupta A. K., Hasegawa T., Katsuki K., Kishimoto K. and Morita M., High temperature air combustion – from energy conservation to pollution reduction, Boca Raton, CRC Press, 2003. Bassuk D. D., Gupta A. K. and Magrab E. B., ‘On-line monitoring of gaseous flames for air–fuel ratio control’, 27th Intersociety Energy Conversion Engineering Conference, San Diego, CA, 3–7 August 1992, paper no. 92-9226. Gupta A. K., Ramavajjala M., Chomiak J. and Marchionna N., ‘Burner geometry effects on combustion and emission characteristics using a variable geometry swirl combustor’, J. Propulsion and Power, 1991, 7 (4), 473–480. Richards, G., ‘The changing energy picture: The role for advanced sensors and control’, paper presented at the 2005 AFRC Annual Meeting, Atlanta, GA, September 2005. Zhang Y. B., Pickrell G. R., Qi B., Safaai-Jazi A. and Wang A., ‘Single-crystal sapphire-based optical high-temperature sensor for harsh environments’, Opt. Engng, 2004, 43 (1), 157–164. Berkovic G., Rotter S., Shafir E., Scandale W. and Todesco E., ‘Wavelengthmodulated fiber optic sensor for high precision displacement measurement’, Rev. Scient. Instrums, 2002, 73 (10), 3687–3691. LopezHiguera J. M., Morante M. A. and Cobo A., ‘Simple low-frequency optical fiber accelerometer with large rotating machine monitoring applications’, J. Lightwave Technol., 1997, 15 (7), 1120–1130. Yu M. and Balachandran B., ‘Acoustic measurements using a fiber optic sensor system’, J. Intell. Mater. Systems Struct, 2003, 14 (7), 409–414. Bae T., Atkins R. A., Taylor H. F. and Gibler W. N., ‘Interferometric fiberoptic sensor embedded in a spark plug for in-cylinder pressure measurement in engines’, Appl. Opt., 2003, 42 (6), 1003–1007. Boiarski A. A., Pilate G., Fink T. and Nilsson N., ‘Temperature measurements in power plant equipment using distributed fiber optic sensing’, IEEE Trans. Power Delivery, 1995, 10 (4), 1771–1778. Lee K. Y., Velas J. P. and Kim B. H., ‘Development of an intelligent monitoring system with high temperature distributed fiber-optic sensor for fossil-fuel power plants’, IEEE Power Engineering Society General Meeting, ieeexplore.ieee.org. Steenkiste V. and Springer G., ‘Strain and temperature measurement with fiber optic sensors’, New York, Technomic, 1997. Varghese O. K., Kichambre P. D., Gong D., Ong K. G., Dickey E. C. and Grimes C. A., ‘Gas sensing characteristics of multi-wall carbon nanotubes’, Sensors and Actuators B, 2001, 81, 32–41. Schechter I., Ben-Chorin M. and Kux A., ‘Gas sensing properties of porous silicon, Analyt. Chem., 1995, 67, 3727–3732. Li J. H. and Yu M., ‘Sensor coverage problems in wireless ad hoc sensor networks,’ Int. J. Sensor Networks, 2007, 2, (3/4), 218–227.


10 Advanced monitoring and process control technology for coal-fired power plants Y . Y A N , University of Kent, UK

Abstract: To meet increasingly stringent standards on combustion efficiency and pollutant emissions and to maintain fuel flexibility, advanced monitoring and control technologies have become highly desirable in the power generation industry. This chapter describes the current state in the development of such technologies for the optimised operation of coal-fired power stations. Monitoring issues that are covered are concerned with the operation of fuel bunkers, pulverising mills, pulverised fuel injection systems, and furnaces. Other issues such as on-line particle sizing, flame stability monitoring, on-line fuel tracking, and flame imaging are also included. Recent advances in control techniques for the optimisation of pulverising mills, pulverised fuel splitting control, and furnace and boiler operations are described. Key words: monitoring and measurement, pulverised fuel flow, particle size measurement, flame imaging, pulverising mill control.

10.1

Introduction

Coal-fired power stations are burning an increasingly varied range of fuels and fuel blends, including sub-bituminous and lower volatile coals and biomass of varying composition and combustion properties, under tight economic and environmental constraints. Since existing coal-fired plants are not designed to burn such a diverse range of fuels, the power generation industry has to overcome a range of technological problems such as poor combustion efficiency, increased pollutant emissions and other operational issues such as poor flame stability and slagging and fouling. The recent trend in operating power plants in variable load in response to changes in electricity demand has exacerbated the aforesaid problems. To meet the increasingly stringent standards on combustion efficiency, pollutant emissions and renewables obligations and to maintain fuel flexibility, 264 © Woodhead Publishing Limited, 2010

Advanced monitoring and process control technology

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10.1 Typical fuel supply and distribution system in a coal-fired power plant.

advanced monitoring and control techniques have become highly desirable in the power generation industry. In electrical power generation solids fuel is supplied from a bunker into a pulverising mill and the pulverised fuel is then pneumatically conveyed towards the furnace by splitting a larger fuel pipe into smaller ones through bifurcations and/or trifurcations. The fuel distribution network feeds a matrix of burners on a wall-fired or a tangentially fired furnace. Each power generation unit at a coal-fired power station can have typically 20, 24 or 32 or 48 burners. A simplified example of the fuel supply and distribution system is illustrated in Fig. 10.1. Advanced sensors and process control techniques to permit on-line measurement and subsequent control of the fuel/air flows in individual pipes, the flames of individual burners, and the optimised operation of fuel bunkers and pulverising mills have been regarded as a priority technological development by many leading power generation organisations and government departments (CRF/BCURA, 2004). This trend is further enhanced by the increasingly stringent emissions legislation, better plant maintainability, increased fuel flexibility and the progressive implementation of the carbon capture and storage strategy (APGTF, 2009). The successful development of advanced sensors and control systems will lead to increased fuel flexibility and better control of emissions, which will ultimately improve plant economical performance and viability. For instance, better monitoring and control of the combustion process will result in low carbon levels in ash, allowing ash residue to be used in cement manufacture (because of a low


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and controlled carbon content), thereby giving revenue instead of disposal costs. This chapter describes the current state in the development of monitoring and control technologies for applications in coal-fired power stations. Monitoring issues that are covered in this chapter are concerned with fuel bunkers, pulverising mills, pulverised fuel injection systems, and furnaces. Other measurement issues such as on-line particle size measurement, flame stability monitoring, on-line fuel tracking, and flame imaging are also included. Control techniques associated with pulverising mills, pulverised fuel splitting, and furnace and boiler operations are described and discussed. The monitoring and control techniques are aimed not only to achieve the optimisation of existing plants but also to provide a useful reference for the specification and design of efficient new-build installations. Some topics such as continuous level monitoring of fly ash and continuous emissions monitoring, although very relevant to the scope of this chapter, are excluded because of length restrictions. Many of the measurement and monitoring techniques described in this chapter are at the stage of being trialled on power stations but are not yet established practice.

10.2

Advanced sensors for on-line monitoring and measurement

The coal- and biomass-fired combustion system can be divided into a number of individual processes that are interconnected to each other from fuel supply to emission stacks. Each process requires on-line monitoring and measurement for different reasons. This section highlights the problems that require monitoring and measurement, and the solutions that are available or proposed to resolve them. The topics that are covered in this section include the monitoring of fuel bunkers, pulverising mill, fuel flow rate and particle size distribution, on-line fuel tracking, flame detection, flame stability monitoring, and flame imaging.

10.2.1 Fuel bunker monitoring It is essential to measure continuously the level of fuel in bunkers and blending silos that feed the pulverising mills and burners. Unreliable levels of fuel in the bunkers can potentially interrupt electricity generation and cause disruption in service. Maintaining a constant supply of fuel in the bunkers has proven to be a challenge. It is therefore desirable to install fuel bunker monitors for continuous level monitoring. The bunkers are often filled by a tripper car system, which moves along a railcar track dispensing the fuel into bunkers. Continuous level measurement of the fuel levels in the



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bunkers allows the automated control of the tripper car system. However, the environment in which the monitors operate is very hostile, including dusty atmosphere above the solids fuel surface, wide variations of ambient temperature and humidity (from hot and humid summers to cold winters), and a variety of solid fuel materials within the bunkers. Several types of fuel bunker monitor have been developed in recent years. They operate on different sensing principles such as radar, ultrasonic, laser, acoustic, capacitance, and load cells. Monitors operating on radar principles use a frequency-modulated continuous wave (FMCW) that can transmit through the dusty atmosphere and be reflected by the fuel surface. This type of monitor is able to provide reliable echo profiles of the fuel in the bunker. For instance, the 24 GHz FMCW SITRANS LR460 monitor (Siemens, 2009) has a small stainless steel horn antenna which requires a mounted opening of only 10 cm and can measure very difficult solids materials within bunkers at ranges of up to 100 m. The ultrasonic continuous level monitor uses a transmitter to generate an ultrasonic pulse and measures the time it takes for a reflected signal to return to a receiver (Koeneman and Sholette, 2006). There are several laser-based fuel level monitors on the market. This type of monitor is often termed TDR (time domain reflectometry). It is claimed that such laser-based monitors have superior dust penetration characteristics and are complete eyesafe, requiring no special permit or safety precautions (Optech, 2006). Some manufacturers claim their TDR coal bunker monitors have outperformed ultrasonic level meters (Endress + Hauser, 2009).

10.2.2 Pulverising mill monitoring Coal is fed into a pulverising mill where it is ground into a fine powder to allow pneumatic transportation and efficient combustion. Coal-fired power stations in some countries, such as those in the UK, are obliged to vary their electricity output in response to demand, which results in regular mill startups and shut-downs. In many cases, pulverising mills are shut down and then restarted before they have cooled adequately, which creates a potential fire hazard within the mill. Mill fires could occur if the coal stops flowing in the mill and the static deposit is heated for a period of time. The problem is pronounced with the co-milling of biomass and coal owing to the higher volatile contents in biomass. Meanwhile, since biomass is often fibrous and non-friable, it is uneconomical to attempt to grind biomass to the same size as coal. The behaviours of coal and biomass blends during milling are not well understood. Actual monitoring data on the milling of blends of coal with biomass and alternative fuels will allow the development and validation of mill performance models. There is therefore a pressing need to continuously monitor and optimise the milling process. It appears that


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limited research has been undertaken in this area compared to bunkers, boilers, generators, and other plant components. Traditionally, an on/off sensor is mounted on the top of the mill to indicate a high level of fuel in the mill (Koeneman and Sholette, 2006). A high-level indication prompts the operator to manage the fuel feed into the mill and reduces blockage and back-ups. The on/off sensor uses commonly a radio frequency (RF) signal. A change in RF admittance indicates the presence of fuel or even the quantity of fuel in contact with the sensor (Koeneman and Sholette, 2006). In recent years continuous detection of the coal level in a pulverising mill has been studied to improve its operational efficiency and reduce downtime. In the majority of cases vibration sensors (accelerometers) or acoustic emission sensors (microphones) are employed to monitor the operational conditions of the mill and infer the level of fuel in the mill. A single or two accelerometers are normally mounted on the bearing housing to pick up the vibration from the mill shaft (Behera et al., 2007; Su et al., 2008). Multiple microphones are mounted on both sides of the mill with respect of its axis (Bhaumik et al., 2006). Since the signals from both types of sensor are susceptible to contamination by strong background vibration or acoustic noise, a range of signal processing methods have been employed to extract useful information. These include frequency domain analysis, wavelet transform, Hilbert transform, and neural network (Yu et al., 2004; Bhaumik et al., 2006; Kang et al., 2006; Zhang and Trulen, 2006; Behera et al., 2007; Su et al., 2008). Signals from acoustic and vibration sensors are often combined with other mill operating parameters such as pressure difference, drive current, and inlet/outlet temperature (Zhang and Trulen, 2006; Su et al., 2008) to estimate the level of fuel and the operational condition of the mill. Data modelling techniques have long been applied to extract useful information on milling performance by analysing archived databases (which represent the history of the mills) available at power plants. Mathematical modelling has also been combined with mill data modelling techniques to enhance the real-time performance of the models. For instance, a multisegment non-linear mathematical model for vertical spindle mills can be developed by analysing the engineering and physical processes such as heat, energy, and mass flow balances (Wei et al., 2006; 2007). All the variables and parameters in the model have clear engineering and physical meanings so the model provides a transparent view of milling processes which is understandable by plant engineers.



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10.2.3 Pulverised fuel flow metering It is well known that poor pulverised fuel distribution between the feed pipes towards the furnace has resulted in a range of operational problems. These include burners operating off design specification either fuel rich or lean, heavily loaded fuel pipes surging or even plugging, uneven and accelerated wear on conveying pipelines, and flame impingement on furnace walls causing wall corrosion. Despite the use of matched outlet pipes and riffle devices, uneven distribution of pulverised coal inevitably occurs. The mass flow rate and velocity of fuel particles in each feed pipe are known to be crucial parameters influencing the operation of fuel injection systems, combustion efficiency, and pollutant emissions (Yan, 2001; 2002). These parameters should be measured and subsequently controlled to achieve fully balanced and optimal fuel supply to the furnace. The fluid flow in a pneumatic pipeline is essentially a solids–gas two-phase mixture. In the case of co-firing coal with biomass the flow becomes a coal–biomass–air threephase mixture. However, it is the mass flow rate and velocity of the solids phase that are of primary interest to the plant operators. Fuel particles in the distribution pipework are normally very dilute. For instance, if fuel particles are conveyed in a feed pipe of 20 in (508 mm) in diameter at an estimated mass flow rate of 10 tons/h with a velocity of 25 m/s, then the mass concentration of the fuel is 0.6 kg/m3, which is equivalent to a volumetric concentration of around 0.1% across the pipe section (Yan, 2002). This dilute dispersal of fuel particles in a large duct poses a difficult flow measurement problem. Substantial effort has been put into the development of pulverised fuel flowmeters in the past two decades (Yan, 1996). In addition to thermal, electrical, and acoustical methods, almost all regions across the electromagnetic spectrum, from gamma rays to microwaves, have been applied to develop suitable devices for this application. Among the proposed techniques electrostatic, microwave, and optical types are relatively more developed. Demonstration trials of such meters have been conducted on coal-fired power stations in the UK, USA, Germany, and China (Yan, 2002; Cai et al., 2005). Figure 10.2 shows the different types of electrostatic sensors that have been used to measure the velocity of pulverised fuel. A pair of sensors is normally used to derive particle velocity through correlation signal processing (Fig. 10.3). The large size of the fuel feed pipes, particularly those greater than 500 mm in diameter, makes non-intrusive spool-piece flow sensors less attractive because of their potential difficulties in installation and high capital costs. For such large pipe sizes, sensors based on intrusive probes offer certain advantages and flexibility over spool-pieces (Yan, 2002; Cai et al., 2005; Krabicka and Yan, 2009). Despite substantial effort in developing pulverised fuel flow sensors using


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10.2 Different electrostatic sensors for the velocity measurement of pulverised fuel.

10.3

Principle of cross-correlation velocity measurement.

a range of sensing techniques, progress that has been made is limited. If there is anything that is relatively more successful, it is the correlation-based fuel particle velocity measurement. Few of the proposed techniques are capable of providing absolute concentration measurement and hence absolute mass flow rate measurement (Yan, 2002).

10.2.4 On-line particle sizing On-line measurement and optimisation of coal fineness and size distribution have the potential to reduce carbon-in-ash levels and NOx emissions (Miller et al., 2000). The coal fineness and size distribution are dependent primarily upon the performance of the pulverising mill and the fuel properties. Most



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10.4 Electrostatic particle fineness sensors under test (Malmgren et al., 2003)

particle sizing techniques currently being used in laboratories are unsuitable for on-line applications (Malmgren et al., 2003). In recent years a number of techniques have been proposed for on-line monitoring of coal fineness and size distribution. These include methods based upon electrostatic, acoustic, optical, and imaging methods. However, progress made in on-line particle sizing is very limited in comparison with other areas of research in combustion instrumentation. The use of electrostatic sensors for the detection of particle size has generated some interest in both industry and academe in recent years. Two electrostatic sensors mounted mutually perpendicular to one another right after a bend on the mill outlet pipe (Fig. 10.4) have been used to determine mill outlet particle size (Miller et al., 2000). The natural particle segregation in the pipe bend provides the basis for particle fineness detection. The online indication of ‘fineness’, that is percentage of particles greater than 159 μm, is achieved with limited reference data obtained through rotorprobe sampling. Although test data have shown a crude agreement with the classifier speed, the effectiveness of the approach is not yet established. Zhang and Yan (2003) have studied the possibility of deriving median particle size using an electrostatic mesh sensing grid. The sensing grid has been tested on a small-scale laboratory test rig. In the algorithm developed the ratio between the powers of two sub-sequences derived from the electrostatic signal is used as a particle size indicator. Trials of acoustic techniques for particle sizing have been undertaken at Longannet Power Station in Scotland (Pattinson and Miller, 1997). Similar work has also been performed by RWE npower in co-operation with Process Analysis and Automation Ltd (Malmgren et al., 2003). In both cases the system comprised acoustic transducers installed on the mill door, mill outlet, and a burner pipe. Power spectra of the acoustic signals were found


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to change with the mill coal flow rate and the mill product particle size distribution. However, direct quantitative relationships between the spectra obtained and the particle size distribution were not reported. Cai et al. (2005) applied the light transmission fluctuation method to measure the mean size of pulverised coal. A light beam produced from a diode laser beam was used to traverse through the particle flow before reaching an optical fibre and a photodetector. The mean particle size was derived from the voltage signal from the photodetector. An intrusive probe made of ceramics was used to house the optical components and ensure resistance to abrasive erosion by the fuel particles. Digital imaging techniques have been applied to measure the size distribution of pulverised fuel (Carter and Yan, 2007). A low-cost charge coupled device (CCD) camera is used to capture the images of particulate flow field, which is illuminated by a low-cost laser sheet generator. The particle size distribution is then determined by processing the images. Results obtained on an industrial-scale combustion test facility demonstrated that the system is capable of measuring particle size distribution, which is consistent with reference data from a laser-scattering-based particle size analyser (Chinnayya et al., 2009).

10.2.5 Flame stability monitoring Existing power plants monitor the brightness or intensity of flames in the interests of safety through the use of photo sensors built into optical detectors called ‘flame eyes’. The detectors use this information to indicate flame ‘present’ or ‘extinguished’, allowing automatic shut-down of fuel feed mechanisms in the absence of a flame. In the past few years some development work has been undertaken to measure the stability of a flame through advanced flame monitoring. This is achieved by ‘tapping’ the signal from an existing flame eye and processing the resulting data as an analogue signal using a dedicated signal processing system (Carter et al., 2009). The basic principle of flame stability monitoring is illustrated in Fig. 10.5. Through analysis of the flame signal the flame intensity and oscillation frequency are measured. The flame stability is indicated by the degree of fluctuations of the measured flame intensity and oscillation frequency. The flame stability monitoring system described above has been used to obtain immediate, quantified information about the combustion conditions of all the burners of the same unit on a coal-fired power station. Figure 10.6 shows the structure of the system hardware. Owing to the safety critical nature of its operation, each flame eye undertakes an independent periodic ‘self-check’. Since the flame eye does not output a valid flame signal during the self-check period, a ‘blinding signal’ from the flame eye is fed to the system so that the software suspends data acquisition and processing



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10.5 ‘Flame eye’-based flame stability monitoring.

10.6 Structure of a multi-channel flame stability monitoring system.

temporarily. The software displays the flame stability information for all the burners on the top layer of the user interface and for groups of three burners of the same mill on the second layer.

10.2.6 On-line fuel tracking Many power stations store fuel on large stock piles and it comes from a diverse range of sources, with varying type and quality, including subbituminous coals and biomass. It is important to know which fuels are located at specific points in the coal-handling system from the stockyard to the burners, however, the logistical problems involved in keeping track of fuel on the stock piles are often insurmountable. Without an effective fuel-


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10.7

Basic sensing arrangement of the fuel-tracking monitor.

tracking system, the mills and burners may be inappropriately set, and this has serious safety implications and may prevent an appropriate mix of fuels being burned to meet new CO2 targets. If the type of fuel being fired is known in real time, the plant engineers can use combustion optimisation software packages to configure the plant for best possible efficiency and minimum emissions. Some on-line coal analysers and coal-tracking systems operating on radiometric, microwave, or passive tagging techniques have been proposed. However, these systems are very expensive and require complex installations. Recent research has demonstrated that on-line fuel tracking can be achieved through advanced flame monitoring (Xu et al., 2004; 2005). Three different wavelength bands of light generated by the flame are received. The basic sensing arrangement of the fuel-tracking monitor is illustrated in Fig. 10.7. The monitor is designed to extract as much information about the combustion flame as possible. It has the same installation specifications as the traditional flame eye (section 10.2.5) so that it can be easily fitted to the existing sight tube that is normally mounted to prevent the monitor from excessive thermal radiation from the flame and provide mechanical support for the monitor. Once the signals are available from the fuel-tracking monitor, various parameters are derived through digital signal processing (Xu et al., 2004; 2005). The first step is to extract the ‘features’ that will be used to train a fuel-tracking neural network. These features cover both time and frequency domains. Wavelet analysis of the signals is also undertaken and certain signal features, such as the number of zero crossings, are considered. In the time domain, the direct current (d.c.) level and alternating current (a.c.) level are calculated and in the frequency domain quantitative flicker frequency and normalised a.c. power of the flame signal are used. An illustrative neural network for fuel tracking of eight different fuels is shown in Fig. 10.8. The principal component analysis (PCA) layer which isolates the most important features in each case makes the network faster and easier to train as well as enhancing tracking reliability (Xu et al., 2005). To illustrate the role of PCA



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10.8 Basic neural network for on-line fuel tracking.

10.9 Three-dimensional plot of the first three principal components.

in the classification of flame features according to fuel type, a threedimensional (3D) plot of the first three principal components is given in Fig. 10.9. It is clear that there are eight different clusters in spite of a certain degree of overlap between them. It is important to note that it is unnecessary to train the network to identify individual fuels (e.g. the specific mine from which it is extracted) but rather what group the fuel falls into in regard to its combustion properties. It is thus not necessary for the system to have ‘seen’ the particular fuel before, so long as it falls into a trained type grouping.


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10.2.7 Flame imaging A conventional flame detector uses a single infrared or ultraviolet photodetector and is limited to a single-point detection of the flame owing to the fundamental line-of-sight sensing arrangement. Digital imaging techniques are an extension of the conventional optical detection approach and are capable of providing two-dimensional (2D) information of a flame field. With the advent of high-performance and low-cost imaging devices in recent years, the application of digital imaging techniques to advanced monitoring and characterisation of combustion flames is becoming increasingly widespread. A range of measurements can be derived from 2D images of the flame when a side view of the flame is available (Lu et al., 2004). These include spreading angle, ignition point and ignition area with respect to the burner outlet, brightness, uniformity, oscillation frequency, temperature distribution, and soot concentration. Some of the parameters are more important than others, depending on the purpose of the measurement and the camera installation arrangement. When the root region of the flame is optically accessible, as shown in Fig. 10.10, ignition points, which form the flame front where fuel particles become ignited, can be identified readily through image processing. A stable flame requires a steady flame front at which the heat lost and heat release of the fuel are well balanced at the ignition temperature of the fuel. The ignition area is a measure of the normalised area encompassed between the

10.10 Definitions of some of the flame parameters.



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burner outlet, flame front, and the spreading angle (Fig. 10.10), which gives the integrated information of flame ignitability (Lu et al., 2004). Another important flame parameter is the oscillation frequency (sometimes referred to as flame flicker), which is a good indication of flame stability and internal structural variability. To quantify this parameter, a random signal is reconstructed by adding and normalising all the grey levels of the individual pixels (corresponding to the radiation intensities of various points) in an area of interest in a flame image and then repeating this process for a series of consecutive flame images (Huang et al., 1999; Lu et al., 2006). The oscillation frequency is defined as the power-density-weighted average frequency in the frequency domain. Although the oscillation frequency of any part of a flame can be studied in principle using this method, the root region and middle region of the flame field are of primary interest to combustion engineers (Fig. 10.11). The root region encompasses essentially the area where the flame front fluctuates (normally from the burner outlet to the maximum possible ignition point). The ignition point and oscillation frequency as outlined above have been used to study flame stability and other characteristics of complex combustion processes such as co-firing biomass with coal (Lu et al., 2008; Molcan et al., 2009) and oxycoal combustion. Flame temperature and its distribution provide fundamental information on the combustion process, including coal devolatilisation, radiative heat transfer, pollutant formation, and the cause of combustion problems such as slagging and fouling (CRF/BCURA, 2004). Digital imaging is an effective

10.11 Definitions of root and middle regions of the flame field.


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tool for the measurement of flame temperature and its distribution, which is very difficult to measure using other techniques. Several research groups are working actively to develop imaging-based flame temperature monitoring systems in recent years (Jiang et al., 2002; Lu and Yan, 2006; Wang et al., 2010). In most cases two-colour or multi-colour pyrometric techniques are applied to determine the flame temperature and its distribution. Apart from flame temperature, there have been attempts to extract other information using advanced signal and image processing algorithms. For example, Sbarbaro et al. (2003) used PCA and generalized Hebbian learning to extract the meaningful components from flame images. It was found that some principal components of a flame image from the blue channel are related to fuel and air flow rates. In addition to the 2D flame imaging work, there have been extensive activities to measure 3D temperature distribution across a flame field. Multiple cameras are normally installed on the furnace walls (Luo and Zhou, 2007; Gilabert et al., 2009). For instance, a total of 12 CCD cameras are installed on a power plant furnace to obtain 3D temperature of the flame field (Luo and Zhou, 2007), as shown in Fig. 10.12. The temperature

10.12 Installation of 12 CCD cameras for the measurement of 3D flame temperature (Luo and Zhou, 2007).



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distribution is derived by reconstructing the 3D flame field from the 2D flame images using tomographic and pyrometric techniques. Apart from flame temperature distribution, other 3D characteristics such as luminosity distribution, volume, surface area, orientation, and circularity can also be derived through the use of reconstruction algorithms (Bheemul et al., 2002; Gilabert et al., 2007). It must be said that the 3D flame imaging systems have indeed provided information that would otherwise be impossible to obtain using 2D systems. However, the use of multiple cameras on power plant furnaces can be costly and sometimes prohibitive owing to high capital cost and regular maintenance requirements.

10.3

Advanced control

Because of the inherent complexity and interaction of a larger number of physical and chemical processes in coal/biomass combustion, conventional control techniques are often not effective or inapplicable. Current practice and development of advanced control techniques for improved operation of coal/biomass combustion processes are based on neural network, fuzzy logic, and expert systems. The targeted variables to be controlled and optimised are associated with basic plant equipment such as pulverising mills, pneumatic conveyers, and boilers.

10.3.1 Pulverising mill control The pulverising mill is notoriously difficult to control because of its complex physical operation, long time delay, and the impracticality of installing conventional process sensors. It is also difficult to develop a mathematical model of the mill for control purposes partly because of the wide coal grindability and variable particle size distributions. Good progress in developing advanced control systems has been made in recent years with three typical examples being given as follows. Fukayama et al. (2004) developed an adaptive state estimator/model for the advanced control of a coal mill. The model considers particle size distribution in the form of a parametric description and coal grindability. The variables to be controlled are the fuel flow through the mill and particle size distribution at the mill outlet. The differential pressure and motor current of the mill (both depend on coal grindability) are the inputs to the control system. The system has been tested on a pilot plant and on a 1000 MW power station. An expert control system using acoustic signatures from the mill has been developed (Bhaumik et al., 2006). The control system relies on a ‘knowledge base’ which is derived from a set of acoustic signatures under different operational conditions of the mill. A neural network is incorporated to


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represent pulverising characteristics of the mill and resulting particle size distribution. A multi-variable control system for the optimisation of a ball-mill coalpulveriser has been proposed (Zhou et al., 2003). The system is based on a three-neural decoupling control mechanism and is able to cope with long delay and strong coupling in the system. The method has been tested on a full-scale plant.

10.3.2 Fuel splitting control Without reliable control actuators, the benefits to be gained through the installation of pulverised fuel flow meters are limited. In comparison with pulverised fuel flow metering, splitting control of pulverised coal is embryonic. An earlier review has indicated that several industrial organisations in the USA and Denmark have attempted to develop control devices such as adjustable bifurcators/trifurcators and variable-orifice dampers (DTI, 2001). However, plant tests have shown that these devices have only had very limited success to date. Experimental tests were conducted on a small-scale test rig (pipe diameter 40 mm) on which a butterfly valve was used as an actuator (DTI, 2002). Some fundamental research was undertaken on a laboratory rig, where air was injected either upstream or downstream of the splitter to deflect the flow (Bradley, 1990).

10.3.3 Furnace and boiler control There are significant control problems that should be resolved on the furnace and boiler level. For example, the development of a coordinated control strategy for the control of the main steam pressure and power output of a boiler–turbine system has been reported (Li et al., 2005). The boiler–turbine system is a very complex process which is multivariable, nonlinear, and slowly time-varying with large settling time. There also exist strong couplings between the main steam pressure control loop and the power output control loop. The control strategy is implemented in two levels: a basic control level and a supervision level. Conventional proportional–integral–derivative (PID) controllers are used in the basic level to perform basic control functions while the decoupling between the two control loops can be realised in the higher level. Fuzzy reasoning and autotuning techniques are incorporated in the control system. Another example is the use of flame imaging results for the control and optimisation of coal-fired furnaces (Kiehn and Schmidt, 2009). The closedloop control system aims to optimise the air/fuel ratio and its distribution on each burner level. It is based on flame imaging sensors and combustion process models that are established through self-learning neural nets.


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10.13 Imaging and neural net based combustion control system (Kiehn and Schmidt, 2009).



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Multiple imaging sensors are installed on the furnace walls in order to acquire unique information directly from the combustion chamber about ignition, burning and burn out behaviours. All combustion-related data are read from the control system permanently and on-line via an interface (Fig. 10.13). The PiT Indicator/Navigator (Fig 10.13) then correlates these data with the information from the imaging sensors. The control system has been applied at several power stations not only to improve combustion efficiency but also to reduce the content of unburned carbon in the fly ash so that it is saleable to the building industry.

10.4

Future trends

Despite a range of developments and advances that have been made in the areas as described in sections 10.2 and 10.3, a range of issues remain to be resolved. The following trends in future development are expected. Previous and existing work in the area of pulverising mill monitoring focuses either on the use of acoustic emission or vibration sensors incorporating signal processing algorithms or on data modelling techniques. Both techniques should be combined to improve the performance of the monitoring system. Other sensors for the monitoring of other mill parameters should be integrated in the system, including the mill load, inlet primary air flow rate, differential pressure of the primary air, inlet and outlet temperatures, and particle size distribution at the mill outlet. Apart from the desired fuel level in the mill, the system should also be able to predict pocket fires, particularly in the co-milling of biomass and coal and during mill start-ups and shut-downs as well as an indication of the overall operating condition of the mill. Once the improved monitoring of a pulverising mill is achieved, more effective control and optimised operation of the mill is expected. Plant data exist for mill settings for different bituminous coals and for blends with low proportions of sub-bituminous coals and biomass. Optimal milling conditions should be identified by analysing the data and fingerprinting milling characteristics. This is especially important for higher levels of sub-bituminous coal and biomass utilisation, where moisture and volatile contents and higher intrinsic reactivities can result in serious operational problems. Meanwhile, computational fluid dynamics (CFD) modelling techniques should be applied to simulate the fuel and air flow within the mill, taking account of the volatile components released from the fuel. The CFD modelling results together with a comprehensive graphical description of the conditions inside the mill concerning both gas and solid phases will enable the engineers to pinpoint possible scenarios that could lead to a fire or faulty condition of the mill. Currently, there are few devices and systems that can provide absolute



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measurement of pulverised fuel flow rate and size distribution. A number of prototypes have been installed on coal-fired power stations but few have met the requirements of the plant operators. The increasing trend towards cocombustion of biomass with coal in recent years will mean that flow rate determination and particle size distribution measurement are likely to be more challenging in view of the complex nature of the coal–biomass–air three-phase mixture. Flow sensors operating on electrostatic, microwave, and optical principles have shown their fundamental limitations for the measurement of pulverised fuel concentration and particle size distribution. However, further development in these areas is expected to continue. Additionally, a combination of multi-modal sensing techniques making full use of their individual advantages should be explored. Other methods such as those based on differential pressure and capacitance tomography for absolute concentration measurement are likely to be very difficult. A pulverised fuel flowmeter should normally provide the operator with a set of measurements including coal velocity, mass flow rate, fineness and/or particle size distribution. The installation of multiple flow meters on all burner pipes will result in an enormous amount of data. How such data should be analysed and effectively used for the overall optimisation of the entire plant needs to be investigated. More importantly, the feasibility of feeding the data to the control system for automatic control and optimisation of the plant needs further study. Additionally, relationships between the coal mass flow rate, velocity, fuel/air ratio and resulting flame quality, combustion efficiency, and emissions should be identified. There are still no proven control devices that can adjust the splitting of coal between individual pipes. The absence of such devices will limit the applicability and market potential of the pulverised fuel flowmeters. It is recognised that the split control of fuel particles is an inherently complex subject, particularly in full-scale power station pipes. The dynamic behaviour of fuel particles of different sizes in a large-scale pipe is not well understood and significant fundamental research through coherent experimental and CFD modelling is therefore needed. For instance, the complex interaction between the mass flow rate and the velocity of fuel in the pipe entails sophisticated control algorithms as well as unconventional measurement strategies. Meanwhile, the performance of such a measurement and control system will likely have an impact on the stability of flames and overall performance of the plant. Some plant engineers are experiencing problems with flame eyes, particularly at lower loads where the burners are stable but the flame eyes indicate differently. The problems are compounded by the fact that some burners are opposed wall firing, so flame eyes can be confused by the flames from the opposite side of the boiler. This issue becomes more significant with the installation of over-firing air systems at some power stations. In the


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case of oxyfuel combustion, reliable flame detection is crucial as the properties of an oxyfuel flame can differ significantly from those of an airfired flame in terms of shape, temperature distribution, and flame stability, particularly when the flue gas recycle ratio varies or the grade of coal changes. Imaging devices may be incorporated in existing flame eyes so that they are able to provide extra information such as flame temperature, oscillation frequency, and on-line fuel tracking, as well as performing the conventional flame eye functions. An integrated data fusion and management system will be required to acquire and process the data from all the flame eyes on the same unit. Such comprehensive data will enable power engineers to assess or predict burner conditions, plant equipment wear, and other more complex plant configurations. Further development in digital imaging based flame monitoring is expected. In addition to flame temperature distribution in a full-scale furnace where multiple cameras are installed, additional information about the flame field will be extracted from flame images through advanced image processing and pattern recognition. This additional information may include ignition patterns, oscillation frequency distribution, fuel/air balance between burners, and even concentrations of free radicals such as OH*, CH*, and CN*. The flame imaging data will provide ample information for the validation of CFD models of the flames and furnaces, leading to optimised design and operation of coal-fired plant firing a diverse range of fuels under variable load conditions.

10.5


Selected professional bodies, industrial organisations and research groups that are relevant to monitoring and control of coal/biomass combustion processes are listed below for further information. Other relevant literature can be found in the reference list. Advanced Power Generation Technology Forum (APG-TF), URL: http://www. apgtf-uk.com/ Coal Research Forum, URL: http://www.coalresearchforum.org/ IEA Clean Coal Centre, URL: http://www.iea-coal.org.uk/site/ieacoal/home British Flame: URL: http://www.britishflame.org.uk/ The Institute of Measurement and Control, URL: http://www.instmc.org.uk/ Optech, Canada, URL: http://www.optech.ca Endress + Hauser, URL: http://www.us.endress.com Siemens Milltronics Process Instruments Inc., URL: http://www.siemens.com/level



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Powitec, Germany, URL: http://www.powitec.de/englisch/ PCME Limited, UK, URL: http://www.pcme.co.uk/ Greenbank Group, UK, URL: http://www.greenbankgroup.com/tero-p-flow.asp Instrumentation, Control and Embedded Systems Research Group, University of Kent, UK, URL: http://www.eda.kent.ac.uk/research/default.aspx The Wolfson Centre for Bulk Solids Handling Technology, University of Greenwich, UK URL: http://www.gre.ac.uk/wolfsoncentre Department of Neuroinformatics and Cognitive Robotics, Technical University of Ilmenau, Germany, URL: http://www.tu-ilmenau.de/fakia/4189+M52087573 ab0.0.html State Key Laboratory of Clean Energy Utilisation, Zhejiang University, People’s Republic of China, URL: http://www.ceu.zju.edu.cn/web_en/ceee/w_ceee 07_aleaders.htm State Key Laboratory of Coal Combustion, Huazhong University of Science and Technology, People’s Republic of China, URL: http://www.hust.edu.cn/ english/research/organ/coal.htm

10.6

References

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Part III Improving the fuel flexibility, environmental impact and generation performance of advanced power plants


11 Low-rank coal properties, upgrading and utilization for improving fuel flexibility of advanced power plants T . D L O U H Y´ , Czech Technical University in Prague, Czech Republic

Abstract: This chapter provides a general overview of relatively new but not commonly used techniques of low-rank coal preparation and upgrading. Options such as washing, drying and briquetting are discussed. All the processes contribute to the increase in heating value of the coal and improve the fuel consistency, resulting in more efficient and controllable combustion. Key words: coal upgrading, coal preparation, coal drying, coal briquetting.

11.1

Introduction

Coal as a fuel for power plants will play an important role in the near and far future as there are very large coal supplies all over the world, but the quality of coal will vary considerably and gradual deterioration is expected. Upgrading brings a number of beneficial effects, reducing most of the problems associated with lower-quality coal utilization. Washing results in reductions in the amounts of mineral matter present, including a proportion of trace elements and sulphur. Drying reduces the moisture content, and hence increases the heating value. Briquetting improves the combustion characteristics and facilitates the inclusion of additives which will capture the sulphur present. All the processes contribute to the increase in heating value of the coal and improve the fuel consistency, resulting in more efficient and controllable combustion. This chapter provides a general overview of relatively new but not commonly used techniques of low-rank coal preparation and upgrading.


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11.2

Properties of low-rank coal

The different types of coal can be classified according to the intrinsic chemical and physical properties of the coal itself due to variation in its origin, constitution, and degree of metamorphism. The various ranks of coal, beginning with the youngest, are peat, lignite, sub-bituminous, semibituminous, semianthracite, anthracite, and superanthracite. Different terminologies are used in different parts of the world. Sub-bituminous and bituminous coal are sometimes considered to cover a broad range of hard coals. Use of both lignite and brown coal for the same rank of coal is quite common. The various ranks of coal depend upon how much volatile matter, moisture, and oxygen was excluded from the lignite during metamorphism. The distinguishing characteristics of various grades of coal on an ash-free basis by Campbell (Gaffert, 1950) are shown in Fig. 11.1. The chart shows how the moisture content varies from a maximum with peat to a relatively small percentage with anthracite. Volatile matter has a maximum with low-rank bituminous coal. The percentage of fixed carbon increases steadily from peat to anthracite by grades of metamorphism and accounts principally for the increase in heating value. In general, coals with high moisture and low heating value are classified as low-rank coal. Lignites, together with some of the lower-rank subbituminous coals, are included in this common group. Lignites are brown in colour and frequently show a distinct woody structure. Newly mined lignites usually have a high moisture content and upon exposure disintegrate

11.1 Chemical composition of various grades of coal (except ash).


Low-rank coal properties, upgrading and utilization

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rapidly. They burn with a long yellow flame, which has less tendency to smoke than that from bituminous coal. Lignites can be pulverized and burned when the moisture is reduced to about 28% or lower. Subbituminous coals are black with shiny surfaces and a laminar structure. They do not coke, but burn freely with a decided tendency to crumble in the fire. They are comparatively soft and pulverize easily, burning with a long yellow flame. The low-rank coals have moisture contents in the range 30–70% and are rich in oxygen. The ash content of low-rank coals varies very widely, with most falling within the range 5–50%. The result of the moisture and ash content is that the lower heating value (LHV) of the coal is generally in the range 4–18 MJ/kg, considerably below that for most bituminous coals. Figure 11.2 (Hill et al., 1989) shows properties of low-rank coals from different countries.

11.2 Relative moisture and ash contents and calorific value of various low-rank coals.


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11.3

Influence on design and efficiency of boilers

High moisture in low-rank coal complicates boiler design. An increased mass flow rate of all substances affects boiler size and the capacity of auxiliary equipment. A considerable difference in the flow rate and heat capacity between flue gas and combustion air resulting from the high moisture content in the coal means that a technical limit is approached as to the extraction of heat from the gas in the air heater. This technical limit is due to the approach of the hot air temperature at the outlet of the air preheater to the inlet flue gas temperature, that is, the ‘pinch point’ effect. In addition, the combination of a high moisture content in the flue gas, sulphur dioxide (SO2) and chloride (Cl) content results in a high acid dew point, necessitating high metal temperatures if corrosion rates are to be manageable. As a result, the final flue gas temperatures for low-rank coal boilers are significantly above those for black-coal-fired-boilers. Hence there are two effects of the high moisture content in coal: . .

greater heat loss due to the increased flue gas flow; additional heat loss due to the necessarily higher final flue gas temperature at which low-rank coal boilers must operate.

The maximum thermal efficiency achievable is some 1.5–4 % lower than that for an equivalent hard coal because of the water content (Dlouhy and Kolovratnik, 2004). Measures for utilization of flue gas waste heat have to be applied if high efficiency is required. A feed water heating arrangement (where flue gas is used directly for heating the condensate and feed water) such as a regenerative feed water preheater has been developed and applied in recent German and Czech lignite-fired power plants. A closed-cycle heat exchange system between the flue gas and the condensate is used involving very low temperature differentials and corrosion resistant material (Dlouhy et al., 2007). However, this is a system that would not be economic for most lower-cost low-rank coals.

11.4

Low-rank coal preparation

Preparation is the most widely used method of pre-combustion treatment of coal. Raw coal needs to be prepared properly for safe, economical, and efficient use in coal combustion systems. Coal preparation differs according to the combustion technique used. If combustion is to be carried out on grates, then normally there is only limited fuel preparation needed. Fluidized-bed combustion needs most coals to be crushed. Depending on the fuel properties, maximum grain sizes of between 3 and 20 mm are desired. In all coal pulverizing systems, coal is dried, ground, classified, and then transported to the boilers. Excepting crushing and pulverization, the



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first step of coal pre-treatment can be performed in plants for coal cleaning and classification, which are usually located close to a mine. Coal cleaning, which is often described as preparation for particular markets, is performed in order to reduce the amount of mineral matter and/ or sulphur. Two methods, based on either wet or dry processes, can be used. Coal washing is a common term for all water-based processes. The objective of the operations is to recover the maximum amount of organic matter from the raw material coming from a coal mine. Washing operations are carried out mainly on bituminous and anthracitic coals. Roughly half the bituminous coals mined worldwide are washed. Low-rank coals have high moisture contents, and the most important aspect of upgrading is usually drying. Most low-rank coal is run-of-mine material. Selective mining is carried out in some places to improve the quality of low-rank coals. Less than 15% of worldwide production of lignite and sub-bituminous coal is washed or dried (Couch, 2002). The mineral matter content of coals as mined can range from 5 to 50% and affects the heating value of the coal and its deposition characteristics in a boiler. It can thus affect heat loss from the system and boiler efficiency. The size, distribution, and nature of the mineral matter through the run-ofmine coal can vary widely and depend both on the occurrence in the coal seam and on the mining method. Coal in most preparation plants is crushed to eliminate large particles of coal. Crushing is followed by screening to produce different sized cuts for treatment. Washing operations are generally carried out within three distinct size ranges: for coarse coal a size from 150 to 10 mm, for intermediate from 10 to 0.5 mm (500 μm), and for fine, below 500 μm in size. Removal of loose shale from the coal and separation of particles with high mineral matter content are the most basic priorities of washing. A difference in relative density is utilized to separate particles with different proportions of mineral matter. If lower relative density is used then the cleaner coal particles will classify as a ‘clean coal’ stream. Simple washing plants with one separator (a jig or a dense medium drum) for a wide range of particle sizes tend to reject more usable carbon than multi-stage plants where each size range is optimally separated. Various separation units and their potential applications are described by Couch (1991). For areas where water is in short supply or where severe winter conditions preclude the transport of wet coal, and for some lower rank coals which tend to form slime during wet processing, dry separation methods have been developed. Dry methods are based on differences in physical properties between particles such as density, lustrousness, magnetic conductivity, electric conductivity, and frictional coefficients. For intermediate particle sizes, fluidization methods using air as the medium are generally suitable. For fine coal, electrostatic methods are more applicable. Air-based processes


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tend only to work well for fairly narrow size ranges and also involve dust removal before the air is exhausted. An air-based method utilizing dense– medium fluidized bed (ADMFB), which has been developed recently in China, is described by Chen and Yang (1997).

11.5

Technologies of low-rank coal upgrading

In general, coal upgrading involves drying, liquefaction, gasification, briquetting or coking. Drying and briquetting are the most widely used methods for upgrading of a low-rank coal. The high moisture content and resultant low heating value of low-rank coal affect boiler efficiency and transportation costs. Upgrading technologies increase the calorific value of a low-rank coal by removing water. Dewatering or drying are the processes used for this purpose. Moisture removal can be accomplished through the use of four different technologies – three are thermal and one is non-thermal: . . . .

direct heat by saturated steam; indirect heat utilizing waste heat or recirculated flue gas; briquetting using simultaneous heat and pressure action; electromagnetic radiation similar to that used in a microwave.

Upgrading increases coal energy density, enhances power plant efficiency, and reduces the emission of regulated substances.

11.5.1 Low-rank coal drying Coal preparation for pulverized coal (PC) combustion always includes drying, which must be very intensive, especially if moist lignite is used. Lignite pulverization is aided by the presence of hot flue gases (with temperature up to 10008C), which are extracted from the boiler through recirculation ducting. The lignite is fed from the bunkers through horizontal, closed feeders to vertical flue gas recirculation ducts and falls to the lignite mill. A fan mill, with either a fan impeller or with a series of impact blades located in front of the fan impeller, is used for lignite pulverization. The mill must achieve three objectives: to pulverize, dry, and then distribute the fuel to the combustion chamber. The lignite particles are typically reduced to less than 90 m in size (approximately 60% through a 70mesh screen). The flue gas heat reduces the lignite moisture content down to 5–15%, in other words, to the required level for optimum combustion conditions. The fan enhances turbulent mixing and increases the relative and absolute velocity of the particles and the gas. The disadvantages of this simple drying method consist in the feeding of lignite dust into the boiler together with drying flue gas and all the water vapour formed. Drying



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therefore contributes only to the reduction of an ignition and burnout period of lignite particles, but an increase in boiler efficiency and the reduction of boiler size is negligible. When lignite of extremely high moisture content is used as the fuel, an additional step prior to feeding it into the combustion chamber is necessary for more effective removal of lignite moisture. For this purpose, after the mills, a stream rich in lignite and moisture is directed to specially designed electrostatic precipitators, where the dry lignite particles are separated and then fed to the lower boiler burners. From the lignite electrostatic precipitators, the mixture of flue gases and moisture is directed via induced-draft fans to the stack or to the flue gas desulphurizer (FGD). If the lignite is dried externally, a much smaller boiler can be used. If flue gas is used for drying, heat from the calorific value of coal is consumed for moisture evaporation. The utilization of external heat for drying is more effective. A number of both classic and advanced methods utilizing external heat for coal drying are available. The tubular dryer is among the techniques with the most industrial-scale experience. It has been widely used in Australia, Germany, and India in connection with lignite/brown coal briquetting. The plant consists, typically, of an inclined rotating shell with a tube heat exchanger (see Fig. 11.3). The shell is heated by low-pressure (waste) steam at 0.4–0.5 MPa and at 1608C, which condenses inside the inter-tube space. Brown coal with a particle size of less than 10 mm enters the tubes with a diameter of 100 mm on the upper

11.3 Steam tubular dryer.


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side of the shell, passes through the tubes, and is dried to a 12–15% moisture content. On the lower side of the shell, the dried coal is collected for subsequent use and air with the evaporated moisture is blown out through an electrostatic precipitator, where fine coal particles are separated. It is possible to increase the drying intensity by using a fluidized-bed dryer instead of a tubular one. The method utilizing a fluidized-bed dryer (known as WTA or ‘Wirbelschicht-Trocknung mit interner Abwarmenutzung’ in German) has been demonstrated on a pilot scale in Germany (Klutz et al., 1996). The energy required for drying is supplied via heat exchangers that are integrated in the fluidized bed and heated with low-pressure steam. Fluidization is achieved by a partial recirculation of vapour. Drying is carried out in almost pure steam, which is slightly superheated. At constant pressure, an equilibrium between the steam temperature and the residual moisture of the dried lignite is reached. The required moisture content in the dried coal can be adjusted and maintained constant by controlling the fluidized-bed temperature. For a system temperature of approximately 1108C a residual moisture content of some 12% was reached for German Rhenish coal with an inlet moisture up to 60% (Elsen et al., 2001). Lignite drying in a steam atmosphere which is not diluted by air or flue gas enables the utilization of evaporated coal water in an energetically efficient way. Two vapour utilization concepts have been developed for industrial use: . .

vapour recompression as an open heat pump process for the heating of a dryer; vapour condensation in an external heat exchanger for the preheating of boiler feed water in a power plant.

The WTA drying process has been developed for two different input grain sizes. The coarse-grain variant with particles between 0 and 6 mm is employed where the dried coal must have a specific minimum grain size, for example, for gasification in the high-temperature Winkler (HTW) process or for coke production from lignite. For all other applications, the fine-grain variant with particle size up to 2 mm is usually the more attractive option in technical and economic terms. The fine-grain WTA process can be used as a pre-drying stage in conventional power plants with PC boilers. The finegrain WTA variant with upstream fine milling and integrated mechanical vapour compression is shown in Fig. 11.4. Following cleaning in an electrostatic precipitator, the vapour obtained from evaporated coal water is divided into two flows. The main flow is passed through a steam compressor where its temperature and pressure are raised to around 1508C and 0.4– 0.5 MPa. Compression allows for use of the vapour for the indirect heating of fluidized lignite through heat exchange tubes in the dryer where the vapour condenses. Condensate produced is used to preheat the raw lignite coming from the mill to about 65 to 708C. The rest of the cleaned vapour is



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11.4 WTA variant with integrated mechanical vapour compression.

11.5 WTA variant with external heating.

recirculated and employed for fluidizing the bed. If required, the dried coal is cooled and milled to a grain size which is suitable for following use. Figure 11.5 shows the fine-grain WTA variant without a vapour compressor. Heat for drying is obtained from external low pressure (waste) steam. Vapour from the drier is used for boiler feed water preheating in terms of the water– steam cycle in the power plant. The WTA coarse-grain dryer with integrated vapour compression and coal preheating has been thoroughly tried and tested on a pilot plant with capacity of 53 t/h in Frechen. A fine-grain dryer utilizing vapour condensation with a raw coal input of approximately 210 t/h is under construction in Niederaussem.


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11.6

Schematic diagram of MTE dewatering.

Another method involving mechanical–thermal dewatering is available but has been tried out only on a smaller scale. The main principle of this method, which is also called MTE (or ‘Mechanisch–Thermische Entwasserung’ in German) is based on the fact that much of the water content is not strongly bound to the coal. The MTE process (Fig. 11.6) combines the mechanical press dewatering concept with the use of elevated temperatures in the range 150–180 8C. Such temperatures enable dewatering at substantially lower mechanical pressures and residence times. The raw coal comes to the pressure chamber where it is slightly pre-pressurized by a press stamp. Hot water is distributed evenly on its surface by sprinklers. Saturated steam is introduced into the chamber and the hot water flows through the coal releasing nearly all its heat content. Water leaving the chamber at around ambient temperature is collected in a cold water tank for following utilization in the cooling system of a power plant. The process is repeated, using pressures up to 6 MPa. The potential of the MTE dewatering was recognized both for German moist lignite (Elsen, 1999) and Australian Victorian brown coal (Chun-Zhu, 2004). Laboratory studies have shown that the percentage of water removal depends on the pressure used and increases approximately linearly as a function of temperature. A low-temperature lignite drying system utilizing waste heat from a power plant has been developed at Great River Energy’s Coal Creek Station in Underwood, North Dakota (USA). The lignite, with a typical moisture of up to 40%, comes from the Falkirk mine. The principle is applicable for



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lignite and sub-bituminous coal-fired power plants, which are cooled by evaporative cooling towers. Heat recovered from cooling water can work to dry high-moisture lignite before it is fed to the pulverizers. Circulating cooling water leaving the condenser is utilized to preheat the air used for drying the coal. The temperature of the circulating water leaving the condenser is usually about 498C and can be used to produce an air stream at approximately 438C, which is fed into a fluidized-bed coal dryer. Approximately a quarter of coal moisture is removed from lignite during drying. Its water content decreases from 38% to 29.8% and higher heating value improves by 14% from 14.4 MJ/kg to 16.4 MJ/kg. The moist air from the dryer is then discharged and the dried coal is fed back into the power generation process. Among other benefits, coal drying by waste heat reduces cooling tower make-up water requirements and also provides heat rate and emissions benefits. A variation of coal drying could be accomplished by both warm air passing through the dryer, and a flow of hot circulating cooling water, passing through a heat exchanger located in the dryer (see Fig. 11.7). A higher temperature of drying air can be achieved if hot flue gas from the boiler or extracted steam from the turbine cycle is used to supplement the thermal energy obtained from the circulating cooling water. Great River has been testing an in-situ 75 t/h prototype since January 2006. Design and installation of four commercial-scale demonstration dryers is currently underway. The drying technique utilizing electromagnetic energy was developed by

11.7 Low-temperature lignite drying system.


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CoalTek (USA) to reduce the moisture in low-rank coals prior to being burned. The process uses highly controlled electromagnetic, ‘microwave’ energy to reduce the moisture in low-rank coals. Unique, desired endcharacteristics of the coal, including MJ/kg and sulphur content, can be programmed into the process to create a ‘designed’ coal that meets the specific needs of an individual generation facility or boiler. Processed coal can be an alternative to installing expensive scrubbers at plants needing to come into compliance with SO2 emission limits. The first commercial processing facility was opened in Calvert City (KY, USA) in 2006 and began shipping its processed coal to industrial customers in the mid-west the same year. The plant’s initial capacity of 120 000 t/year was expanded in 2008. The company anticipates substantial growth at other facilities in 2009 and beyond. Fuels Management, Inc. (FMI) has developed a technology for the enhancement of low-rank coal by using established fluid-bed reactor hardware and patented technology to lower the moisture content, significantly increase the calorific value, and reduce mercury content. Coal is dried in a fluidized-bed reactor with oxidizing environment, which is a key element in promoting stability. The process operates at low temperature (3158C) and no outside source of heat is required as 6–8% of the feedstock coal is burned in the process. The finished product is stable with 0.5% moisture. A commercial demonstration plant has been running since 2009. This unit provides 20 000 t/year of product for test burns and commercial design optimization. A pre-combustion refinement process for low-rank coal upgrading using heat and pressure has been developed by Evergreen Energy Inc. The resulting product, still a solid fuel, has a moisture content between 8 and 12% compared to approximately 30% in the raw feedstock, and is branded and sold as K-Fuel. This process improves the heat value by approximately 30%. With the K-Fuel process, raw coal enters a large vessel that subjects it to higher temperatures and pressures, much like a pressure cooker. Under these conditions the porous structure of coal collapses and the heated water is squeezed out, producing fuel with a much lower moisture content. At the same time, the heat and pressure force some of the coal’s tar to its surface. This coats and seals the outside of the coal and helps prevent it from reabsorbing the lost moisture. The amount of energy used in the process to remove water is about half of what it would take to evaporate the same amount of water in a coal boiler during combustion. A 750 000 t/year KFuel processing plant has been built in Gillette (Wyoming, USA). The plant produces refined coal and ships it to customers for test burns as well as on a commercial basis.



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11.5.2 Briquetting Mechanized mining often increases the content of fines in the coal and the proportion of the size fractions suitable for industrial and domestic use decreases. Briquettes or pellets can provide a satisfactory substitute fuel, using the excess fine coal. Briquetting is a traditional form of coal upgrading for domestic use, however, its importance for industrial use is growing. Coal briquettes have been used in the past as smokeless fuels in countries such as Germany, the UK, and the USA on a considerable scale. Furthermore, briquettes can replace sized coal in industrial boilers and in the coal gas furnaces used in chemical production, machinery, and glass industries. Briquettes have also been used on a substantial scale in moving bed gasifiers, where the content of fine coal in coal has to be minimized. Briquettes are produced by hot pressing from pre-dried coal. They consist of partially carbonized coal. During the briquetting process, some (or most) of the volatile matter is removed from the coal and the product burns smokelessly. Whitehead (1997) summarized the advantages and disadvantages of various methods of agglomeration technology. .

. .

.

Mixer agglomeration: this is the simplest and cheapest technique providing the weakest product, simple binders (e.g. water) can be used, conversion of dust to crumb-size product, possible application to condition coals for nearby use. Disk pelletizers (or drums): this is a simple and the next cheapest concept, producing relatively weak pellets with a diameter of 5–80 mm. Roll press: this is a relatively expensive method needing good binders, a uniform product size with an ovoid or pillow-shaped briquetter; it is the only method used in Western Europe to make smokeless briquettes for domestic use. Extrusion: this is a relatively expensive method, needing no binder, with typically a brick-shaped product, and problematic product strength; a traditional method for briquetting both peat and brown coal.

The choice of technology for a particular application depends on the nature of coal used and the required product characteristics, including its handling ability and strength. All the processes are coal-specific in application. Successful development depends both on extensive testing and on assessment work, including evaluation of representative coal properties over the following 10 or 15 years. Economic criteria like the differential between coal cost and product value or binder availability and cost have to be taken into account as well. Briquettes can be made from fine coal, which provides a very low-cost raw material, or from some low-rank coals. In


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addition, the briquettes can be made with limestone as an additive for sulphur capture and reduction of SO2 emission during combustion. For briquetting, coal with very little moisture is required. If moist lignite is used, it must be dried to a water content of around 15%. In general, tubular steam dryers or flue gas dryers are used in briquetting plants. In contrast, pelletizing is possible for a fine coal containing up to 30% of water (Conkle and Raghavan, 1992). Briquetted and pelletized coal is produced on a limited scale in various places, but large-scale applications have been limited because the processes are relatively expensive. In Australia, binderless briquettes are used in power stations to maintain combustion stability when the as-mined brown coal is of poor quality. In China, large quantities of briquettes are used both domestically and industrially, and production totals more than 50 Mt/year. So-called honeycomb briquettes are widely used. For slightly larger-scale use, briquettes burn more efficiently, and the use of briquettes is likely to grow. A solution to larger-scale upgrading of lowenergy black or brown coals is offered by White Energy Company, which is the exclusive worldwide license holder of the patented White Coal technology (WCT). The process (see Fig. 11.8) upgrades low-rank coals by reducing the moisture and agglomerating undersize coal into physically

11.8 Schematic diagram of WCT briquetting plant.



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and chemically stable binderless briquettes that can be handled, transported, and utilized like normal coal. The process involves the crushing and drying of low-rank coals resulting in removal of the coal water content. Hot drying gases are produced through the separate combustion of a small proportion of the coal. Compaction then generates close bonding between the dried coal particles and eliminates nearly all voids. This forms high-density, higherenergy-content briquettes with very low permeability, which is a key factor in providing stability against spontaneous combustion. The briquetting process is a purely mechanical procedure involving material distribution, compaction, cooling, and storage. The product is in a form that can be handled, stored, and transported as conveniently and safely as normal coal. The process requires none of the binders that are normally used to briquette coal, which substantially reduces production costs. Binderless briquetting utilizes natural bonding mechanisms of coal. The ability to generate close bonding between the coal particles (i.e. the application of the compaction force in such a way as to cause the particles to come into intimate contact and establish bonding between them) makes the WCT process different from and more successful than past briquetting attempts. The process has been developed to a commercially viable stage. It is capable of producing low moisture, physically and chemically stable briquettes from sub-bituminous coal at large scale and with attractive economics. The WCT product has an energy content 50–100% higher than the raw coal from which it is derived. To date, over 20 000 t of coal have been upgraded in testing programs. A 90 000 t/annum WCT development plant was built in Australia and the process has proven to operate successfully. Coal samples from China, the USA, Australia, Indonesia, and South Africa have all been successfully upgraded. A fully featured demonstration plant has been in operation since the end of 2007. Further research and development around plant scale-up and design will be conducted, as well as work with different types of coals.

11.6

Utilization of low-rank coal in advanced power plants

In most cases, low-rank coals are utilized as received in PC or fluidized-bed boilers. High moisture content in low-rank coals results in fuel-handling problems, increases in mass rate (tonnage) of all substances including emissions, and it affects the efficiency of boiler and heat rates of a power plant. A low calorific value of the coals precludes long-distance transport because of high costs. Utilization of low-rank coal is therefore limited to a close region of the seam. New benchmarks for lignite-fired power plants set two Neurath blocks F


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and G with a gross capacity of 1100 MW referred to respectively as BoA 2 and 3 (Elsen and Fleischmann, 2008). The units use the BoA (‘Braunkohlekraftwerk mit optimierter Anlagentechnik’ in German) package of advanced optimised lignite technologies with significant improvements to the individual parts of the plant and process steps first employed at Niederaussem. High net efficiency of the power plant of over 43% (LHV) is ascribed to the steam conditions (600/6058C); the steam turbine technology; the nine-stage feed water preheating system; the maximization of waste heat recovery from flue gas and a minimization of auxiliary power needs. Raw lignite with a high moisture content (48–60%) is provided from the opencast mining sites of Garzweiler and Hambach. The lignite is dried using hot flue gases taken from the furnace. The WTA drying principle has not been utilized owing to lack of experience on a large-scale power plant (Smith, 2006). However, the WTA demonstration facility with capacity of 210 t/h has been built next to the Niederaussem BoA unit and commissioning has just begun in 2009. The facility is expected to demonstrate that the WTA system in continuous operation is both technically and economically viable. An overall increase of up to 2.5 percentage points on net thermal efficiency is expected from utilizing the WTA drying technique in future lignite-fired power plants (Stamatelopoulos, 2007). WTA technology is also being proposed as part of a major retrofit planned for the Hazelwood power plant in Australia (Rich et al., 2007). Upgrading brings a number of beneficial effects, reducing most of the problems concerning low-rank coal utilization. Washing results in reductions in the amounts of mineral matter present, including a proportion of trace elements and sulphur, although there may be a small increase in moisture content. Drying reduces the moisture content, and hence increases the heating value. Briquetting improves the combustion characteristics and facilitates the inclusion of additives, which will capture the sulphur present. All the processes contribute to the increase in heating value of the coal and improve the fuel consistency, resulting in more efficient and controllable combustion. The effect of coal pre-drying on unit operation was demonstrated by a coal test burn at Coal Creek Unit 2 in October 2001 (Levy, 2005). The lignite was pre-dried by an outdoor stockpile coal-drying system. On average, the coal moisture was reduced by 6.1%, from 37.5 to 31.4%. Analysis of boiler efficiency and net unit heat rate showed that with pre-dried coal, the improvement in boiler efficiency was approximately 2.6%, and the improvement in net unit heat rate was 2.7 to 2.8%. The test data also showed the fuel flow rate was reduced by 10.8% and the flue gas flow rate was reduced by 4%. The combination of lower coal flow rate and better grindability contributed to reducing mill power consumption by approximately 17%. Fan power was reduced by 3.8% owing to lower air and flue


Low-rank coal properties, upgrading and utilization Table 11.1

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Effect of utilization of dried lignite in Coal Creek power plant

Parameter

Units

Coal dryer Coal dryer Change Units of out of service in service change

Gross power output Throttle steam temperature Reheat steam temperature SHT spray flow Input coal moisture Dried coal moisture Dried coal Total coal flow rate Stack flow rate Specific pulverizer work Total pulverizer power NOx mass emissions SOx mass emissions APH gas exit temperature Stack temperature

MW 8C 8C tonne/h TM% TM% % of total tonne/h m3/h J/kg kW kg/h kg/h 8C 8C

590 532 539 23.6 36.8 0 441 2.763106 9.458 4.206 667 1675 188 84

589 NC 531 NC 539 NC 20.9 2.7 36.8 28.6 14.62 432 2.02 2.737106 0.96 9.017 4.65 4.057 3.53 610 8.52 1641 2.00 183 5 82 2

tonne/h

% % % % % % 8C 8C

gas flow rates. The average reduction in total auxiliary power was approximately 3.8%. Sarunac (2006) evaluated the effect of utilization of dried lignite in the Coal Creek lignite-fired unit with capacity of 600 MW. Results are summarized in Table 11.1. The benefits resulting from an application of coal drying fell into seven main categories: . . . . . . .

reduced fuel costs; reduced ash disposal costs; avoided costs of emissions control; reduced station service power for the forced draft and induced draft fans and for coal pulverizing (but, in some cases, the power requirements for coal drying could increase station service power); water savings; reduced mill maintenance costs; reduced lost generation due to mill outages.

11.7

Future trends in coal upgrading

Low-rank coals are one of the largest energy resources for power and heat generation in the USA, Russia, Central Europe, and much of the Pacific Rim. Coal-based generation is expected to grow by 25%, supplying 46% of a larger total electricity demand by 2020. Recently, a number of advanced methods for coal upgrading have been developed and published. Some of them are designed for a wide range of applications including coal drying before combustion or briquetting; other ones are suitable only for


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gasification or liquefaction processes. New promising methods of low-rank coal upgrading are introduced in the following examples. A low-rank coal upgrading technology adapting a slurry dewatering technology for brown coal liquefaction (Japan Coal Energy Centre, 2009) is under development in Japan: it is known as the UBC process. This process consists of three stages: slurry preparation/dewatering, solid–liquid separation/solvent recovery, and briquetting. At the first stage, moist low-rank coal is, after pulverizing, mixed with recycled oil then laced with heavy oil (such as asphalt), and heated in a shell-and-tube-type evaporator. Vapour recovered from the coal moisture is pressurized and sent to the shell side of the evaporator to utilize the waste heat in the dewatering stage. During that time, laced heavy oil is effectively adsorbed on to the porous surface of the coal, thus preventing spontaneous combustion. At the stage of solid–liquid separation, the solvent is recovered from the dewatered slurry by the decanter; the solvent remaining in the pores of upgraded coal is also recovered by the steam tubular dryer. Solvent separated during both processes is recycled to the slurry preparation tank. Upgraded coal obtained from the UBC process is still in a powdery state, so briquetting is a convenient preparation for transportation over longer distances. A demonstration plant with a capacity of 5 t/day (raw coal-base) has been built in Cirebon of the Java Barat province in Indonesia and promoters hope for early commercialization. The Nu-Fuel process developed by Confluence Coal Combustion LLC (Man, 2009) is another means of upgrading low-rank coals. The Nu-Fuel process involves mild thermal treatment, using heat applied externally to a retort. This treatment reduces the moisture content of the coal to any desired level and also converts the complex hydrocarbon molecules in the raw fuel into simpler compounds capable of rapid combustion. The retort is maintained at about 2158C, a temperature well below the point at which pyrolysis of the coal occurs. The retort contents are subjected to a controlled atmosphere consisting of combustion flue gas that flows countercurrent to the coal being treated. Carbon dioxide (CO2) contained in the blanketing gas is absorbed into the pores of the treated coal, replacing the water driven off. Carbon-to-carbon bonding also takes place on the surface of the coal. The result is that reabsorption of moisture is essentially avoided. The treated fuels have many other improved combustion characteristics, including extremely rapid combustion in a boiler, easy ignition, and stable flames at very low temperatures. The increased reactivity of Nu-Fuel products also makes them potentially superior feedstocks for gasification. The Nu-Fuel process has been thoroughly investigated in bench-scale tests and in a 1 t/day pilot plant. The next phase is to demonstrate the process on a commercial scale. The future utilization of low-rank coal faces both challenges and



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opportunities, including preparation and upgrading, more efficient combustion, and gasification technologies. Efficiency improvements should bring the economic benefits mentioned above and should also be accompanied by a reduction in CO2 emissions, and possibly by other parallel effects such as a reduction in the amount of NOx and SO2 formed.

11.8


The following books dealing with the low-rank coal utilization and upgrading are recommended: .

.

.

Gordon Couch: Coal upgrading to reduce CO2 emissions. CCC/67, London, 2002. The report includes a review of the methods available, and a country by country review of the potential for additional upgrading. The impact of coal upgrading on the thermal efficiency of coal use is discussed, and the countries where there could be the greatest impact are identified. Heinz Termuehlen and Werner Emsperger: Clean and efficient coal-fired power plants, ASME Press, NY, 2003. This book presents the evolution toward advanced coal-fired power plants. Advanced power plants with an efficiency level of 45% are today commercially available and even more efficient plants are in their development phase. Tadeusz Kundra and Arun S. Mujumdar: Advanced drying technologies, Marcel Dekker Inc., NY, 2002. The book offers classification and selection criteria for new and advanced drying systems and compares conventional dryers to novel technologies, including modified fluid bed, superheated steam, and impinging stream dryers.

Information about recent technologies and research projects is available on the following web sites: .

.

.

www.fe.doe.gov/fred/feprograms.jsp?prog=Clean+Coal+Technology – pages of the Department of Energy’s Office of Fossil Energy. The Department typically manages more than 500 active research and development projects spanning a wide range of coal, petroleum, and natural gas topics. www.nextgenenergy.org/ – pages of The NextGen Energy Council (NextGen), a non-profit organization comprising a wide variety of energy and technology leaders, state legislators and energy industry experts. http://www.lignite.com/ – pages of the Lignite Energy Council, which maintains a viable lignite coal industry and enhances development of US lignite coal resources for use in generating electricity, synthetic natural gas, and valuable by-products.


310 . . . . .

Advanced power plant materials, design and technology http://www.iea-coal.org.uk/site/ieacoal/home – pages of IEA Clean Coal Centre, which provides unbiased information on the sustainable use of coal worldwide. www.nedo.go.jp/sekitan/cct/ – contains a survey of clean coal technologies in Japan. http://www.power.alstom.com/home/ – pages of Alstom, a global leader in the world of power generation setting the benchmark for innovative and environmentally friendly technologies. http://www.rwe.com/web/cms/en/8/rwe/ – pages of RWE, one of Europe’s largest power companies involving the most recent technologies for lignite utilization. www.whiteenergyco.com – pages of White Energy Company Limited, a public company based in Sydney and focused on the commercialization of coal-upgrading technologies.

11.9

Acknowledgement

This chapter was prepared with the support of the Research Centre 1M0605 financed by the Ministry of Education, Youth and Sports (MEYS) of the Czech Republic.

11.10 References Chen Q R and Yang Y (1997), ‘Current situation and development of dry beneficiation of coal technology’, Proceedings of the 14th annual Pittsburgh coal conference: Clean coal technology and coal utilisation, Pittsburgh, 23–27 September 1997, University of Pittsburgh. Chun-Zhu L (2004), Advances in the science of Victorian brown coal, Elsevier. Conkle H N and Raghavan J K (1992), Reconstitution of fine coal, Coal Preparation, 11(1–2), 67–76. Couch G R (1991), Advanced coal cleaning technology, IEACR/44, London, IEA Coal Research. Couch G R (2002), Coal upgrading to reduce CO2 emissions, London, IEA Clean Coal Centre. Dlouhy T and Kolovratnik M (2004), Influence of coal composition on boiler efficiency (in Czech), Proceedings of international workshop on Combustion and environment 2004, Ostrava, 15–16 November, 2004, TU Ostrava, Czech Republic. Dlouhy T, Kolovratnik M and Hrdlicka F (2007), Design of new Czech brown coal fired power plants, Proceeding of 32nd international technical conference on Coal utilization and fuel systems, Clearwater, FL, 10–15 June 2007, Coal Technology Association. Elsen R and Fleischmann M (2008), ‘Neurath F and G set new benchmarks’, Modern Power Systems, June 2008, 23–30.



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Elsen R (1999), ‘Wirkunsgradsteigerung durch effiziente Braunkohletrocknung’, BWK, 51 (5/6), 78–84. Elsen R, Blumenthal U, Go¨tte Ch, Kamm J and Von Kossak T (2001), ‘Palnung und Bau der Pilot-Trocknungsanlage Nederaussem’, VGB Kraftwerkstechnik, 81 (6), 68–72. Gaffert G A (1950), Steam power stations, Shangiai, Chiao Dah Book Service. Hill J O, Ma S and Heng S (1989), ‘Thermal analysis of Australian coals’, Journal of Thermal Analysis, 35, 2009–2024. Japan Coal Energy Centre (2009), ‘Low-rank coal upgrading technology (UBC process)’, Japan Coal Energy Center, the Institute of Applied Energy, available from: http://www.nedo.go.jp/sekitan/cct/eng_pdf/2_3d2.pdf (accessed 30 January 2009). Klutz H J, Klo¨cker K J and Lambertz J (1996), ‘Das WTA – Verfahren als Vortrocknungsstufe fu¨r moderne Kraftwerkskonzepte auf Basis Braunkohle’, VGB Kraftwerkstechnik, 76(3), 224–229. Levy E (2005), Use of coal drying to reduce water consumed in pulverized coal power plants, Lehigh University Energy Research Center, available from: http:// www.osti.gov/bridge/servlets/purl/862095-9GniWa/862095.pdf (accessed 12 March 2009). Man A N, ‘Upgrading coals using the NU-Fuel process’, Confluence Coal Combustion, Pittsburgh, available from: http://confluencecoal.com/ resources/Microsoft_Word__nu_fuel_paper_0205.pdf (accessed 2 February 2009). Rich G, Hayes B and Heinz G (2007), ‘Hazelwood 2030’, Modern Power Systems, December 2007, 22–29. Sarunac N, Bullinger C and Ness M (2006), ‘Coal Creek prototype fluidized bed coal dryer’, Proceeding of 31st international technical conference on Coal utilization and fuel systems, Coal Technology Association, Clearwater, FL, 21–25 May 2006. Smith D (2006), ‘RWE to built BoA 2 and 3 without WTA’, Modern Power Systems, April 2006, 11–15. Stamatelopoulos G N (2007), ‘WTA offers big efficiency gain’, Modern Power Systems, December 2007, 17–21. Whitehead J (1997), ‘Briquetting coal to enhance value’, Conference on Additional value of coal, Rotterdam, 25–26 June 1997, London, CoalTrans.


12 Biomass resources, fuel preparation and utilization for improving the fuel flexibility of advanced power plants L . R O S E N D A H L , Aalborg University, Denmark

Abstract: This chapter addresses aspects of using biomass rather than biomass fuels. The concept of CO2 neutrality is discussed, followed by classification of biomasses relevant for power plant use. A brief discussion of conversion technologies is given, as it applies to choice of fuels, followed by issues of biomass resource availability. The chapter also contains chemical and physical characteristics of a variety of biomasses and biomass mixes, as well as a discussion of pretreatment and fuel preparation technologies. Key words: biomass, fuel, CO2 neutral, chemical composition, physical characteristics, classification.

12.1

Introduction

In a carbon-constrained world, it is necessary to consider carefully the advantages and disadvantages of using fossil fuels and subsequently remove carbon dioxide (CO2) from the flue gasses, versus those of replacing all or some of the fossil fuel with biomass, thus negating the necessity for such removal facilities. In the context of power plants, the most cost-efficient approach to this in the short term (probably some 10–15 years, considering the life expectancy of the majority of the existing world’s fossil fuel power plants) is by implementation of some measure of co-firing on existing fossil fuel power plants, where typically solid biomass and fossil fuel are cocombusted in the plant. Several such installations currently exist, mainly in Northern Europe, the USA and in Australia (IEA, 2007a). In the medium to long term, the concept of multi-fuel plants is likely to become dominant, where the firing equipment is designed for flexibility, such that the choice of


Biomass resources, fuel preparation and utilization

313

fuel, within limits, can be adapted to availability, cost and other relevant factors. Using biomass as a fuel to produce heat is not a new idea brought about in response to concerns about CO2 and green house gasses in the latter decades of the 20th century. Indeed, long before mankind realized that the Earth harboured enormous energy resources in terms of fossil material in the form of coal, oil and gas and created an energy system heavily reliant on these, biomass, mainly wood and grasses, was the fuel of choice. However, in the context of the 21st century, using biomass for energy purposes is as far removed from those early uses as can possibly be imagined. Granted, the process of combustion or gasification is the same, but the logistics, the preparation and the energy intensity of the process is on a completely different scale. Our understanding of these processes, and indeed other processes involving the conversion of biomass, as well as the consequences of utilizing these processes, has also increased to a level where we are able to minimize the environmental impact at the same time as maximizing the energy output. The renewed interest in biomass as a primary energy source stems from two very different concerns. One is, of course, climate concerns, and the scientific consensus that there exists a link between releasing increasing amounts of fossil carbon into the atmosphere and global warming. The other, more political, concern, is the regionality of the world’s energy reserves in terms of primarily oil and gas. These are in the vast majority located in regions of the world which might be characterized as politically unstable, and there is a global desire to lessen national dependencies on these fuels and rather build up an energy system that relies on local resources, such as wind, solar and biomass. Leaving aside the political aspects for the purpose of this chapter, and focusing on biomass, it is the concept of local availability combined with potential CO2 neutrality that drives the implementation of biomass in the energy sector. CO2 neutrality, indicated in Fig. 12.1, refers to the balance between the CO2 absorbed by the biomass through photosynthesis, as it grows, and the CO2 emitted as it is utilized in some conversion system. In an ideal world, these are identical, and consequently there is no net increase of the carbon content of the atmosphere, contrary to fossil-based CO2, which represents a net increase as the carbon source has been ‘out of circulation’ for millions of years. True CO2 neutrality is only achieved, however, if the entire process of cultivation, harvesting, processing and transportation is based on renewables, and through life cycle analysis (LCA) it becomes evident that most biomass utilization is not truly CO2 neutral. In general, however, the displacement of fossil CO2 is orders of magnitude greater than that emitted in order to bring the biomass fuel to the power station. Setting aside the conversion process, there is also the consideration that


314


12.1 Simple sketch of atmospheric CO2 increase due to use of fossil fuels (left) and CO2 neutral use of biomass (right).

biomass is the main source of food, fodder and fibre. Given the projected growth of the world population it is unlikely that energy will always be the number one priority in terms of available hectares for energy crops. Biomass can be classified in several ways, according to growth cycle, fibrous structure, aquatic or terrestrial, and primary energy yield. Biomasses can also be classified in a more historical setting based on use in the energy sector, as traditional biomasses and new biomasses. To the former category belong the ‘pure’ biomasses such as lightly prepared wood, straw, grasses, and to the latter belong the different organic waste streams from agricultural, industrial and domestic biomass use. As can be seen in Fig. 12.2, in 2004 by far the main biomass use came from the traditional biomasses. It can also be seen that this mostly went to heating, and only a small fraction of biomasses went through a pretreatment process allowing it to be used for electricity generation. However, this picture is undergoing tremendous change, with more and more biomass undergoing some sort of pretreatment, allowing it to be transported to and used in either a modern electricity-generating power station, as mono-fuel or as a co-firing fuel together with a fossil fuel, or for production of a liquid biofuel. Furthermore, it is certain that the two smaller contributors, agriculture and municipal solid and industrial waste, will claim a significant part of the growth of the market for biomass for energy, mainly through exploitation of a greater number of waste streams than is currently the case. This is indicated in Fig. 12.3, where a wide range of biomasses supplement


12.2 World biomass energy flows (EJ/year) in 2004. For comparison, total primary energy amounted to approximately 470EJ in 2004 (IPCC, 2007).



315

316


12.3

Biomass conversion paths from resource to product (Sims, 2007).

the traditional supplies. In the future, selecting the right combination of biomass and conversion technology will also include the product step, where energy in different forms will have to compete with other utilizations of biomass products. The challenges facing the use of biomass in a resourceconstrained and CO2 conscious world can be summarized as follows: . . . . . .

scarcity of traditional pure biomasses and land for energy purposes; identifying new biomasses, including functional biomass mixes; optimizing fuel preparation techniques for minimum energy use, maximum homogeneity and transportability, as well as compliance with existing fuel handling equipment at power plants; fuel flexibility at the individual plant; developing processes which allow for extraction of various nutrients (e.g. phosphorous) to be recycled; developing combinations of processes which allow for extraction of various valuable by-products.

These issues will be addressed in the following sections.

12.2

Biomass types and conversion technologies

As mentioned previously, there are many ways to classify biomasses. One often used classification is the four-type classification (McKendry, 2002): . . . .

woody plants; herbaceous and grassy; aquatic; manures.

Woody biomasses are characterized by plants having stems that are covered with bark, and which survive over several years. The stems consist mainly of



317

lignin and cellulose, and have a vascular system to transport water and nutrients from the roots to the rest of the plant. Woody biomass is available in different forms, as chips, sawdust, pellets, forestry residue and logs. As such, wood can be a by-product or a dedicated energy crop, typically short rotation coppice (SRC) such as willow. Herbaceous and grassy biomasses are plants that have stems and leaves, but die at the end of the growing season. Annual herbaceous plants die completely, and new plants grow from seeds, whereas biennial (for example carrots and parsnip) and perennial (for example grasses) plants leave a part of the plant surviving underground, from which a new stem grows at the beginning of the next growing season. Aquatic biomasses are, for example, algae (Ross et al., 2008) and seaweed, and are naturally characterized by a high degree of moisture. Finally, manure is a by-product primarily from cattle and pig farming. To a more broad definition of biomass can also be added the following categories: . . .

municipal solid waste (MSW); sewage sludge; animal fats.

MSW is in many countries defined as a biomass, and is utilized for heat and power production to varying degrees in different countries, or is disposed of by land filling. One result of landfills is landfill gas, which is a methanedominated gas emitted through the decomposition of the organic fraction of MSW, and this also represents a biomass resource if captured. An important subcategory of MSW is refuse-derived fuels (RDF), which are based on paper and plastic residues, primarily (Petrou and Pappis, 2009). Sewage sludge is the result of waste water treatment plants, and contains organic material from households, industries and rain water. Animal fats are byproducts from meat processing.

12.2.1 Classification of conversion technologies Biomass conversion technologies are normally classified as 1st, 2nd, or 3rd generation, according to the type of feedstock. First generation technologies take biomass feedstock which could otherwise be used as food, that is primary biomasses. Examples are use of starch and sugars from wheat or maize to produce bioethanol or other bio-alcohols, or rape seeds which are pressed to produce oils or bio-diesel. Use of grains or seeds in direct thermal conversion would also represent 1st generation use. These biomasses could also be used in human or animal food chains, and energy production thus takes place at the potential cost of influencing food supplies and prices. Second generation technologies, on the other hand, use the fractions of biomass which are not used in either human or animal foodstuffs. Examples


318


of these are lignocellulosic biomass (straw, waste wood), animal fats resulting from meat processing, MSW and sewage sludge, thus secondary biomass that has already been utilized for a purpose. Typically, for a technology to be able to utilize 2nd generation biomass feedstock, a higher degree of pretreatment is necessary in order to access and process the organic material. This is particularly true for the use of the lignocellulosic biomass for bio-alcohol production, as the biomass primarily consists of lignocellulose, where the carbohydrates are tightly bound to the lignin (Lin and Tanaka, 2006). Third generation technologies are those utilizing algae for energy production, either directly or by conversion to a liquid biofuel. Algae have spurred considerable interest owing to their high growth rates, high sugar or oil contents, and the fact that they represent a completely new resource, which is not in competition with food production for land. However, whereas 1st generation technologies are already in commercial operation, and 2nd generation technologies either in demonstration or close to commercialization at this time, 3rd generation technologies are still in the future. It is important to realize that a technology can be either 1st, 2nd, or 3rd generation, depending on the feed stock, but that a conversion technology will often be optimized toward a specific biomass. This also means that the biomass classification and the technology classification overlap to some extent, as wood and herbaceous biomass as well as animal fats can consist of primary biomasses as well as residual biomasses. For energy purposes, biomasses are also often classified according to their water content, as this is generally decisive in terms of the conversion technology chosen to process the biomass. Thus, high-moisture biomasses such as algae, manure or sewage sludge would not be suited for processes such as gasification or combustion without prior drying, but instead would be appropriate in technologies where high water content is an advantage.

12.2.2 Available biomass resources For large-scale utilization of biomass it is important to estimate the availability of biomass resources. This is a formidable task, as several factors – technical, political, climatical, demographical – all influence the result. Various estimates and forecasts exist, both on the use of renewable energy based on biomass and on the distribution of this on different types of biomasses. For example, IEA (2007b) indicate a ten-fold increase in biofuels and at least a quadrupling of electricity generation based on biomass in 2030. Parikka (2004) provides data on potential compared to land use in 2004, and shows that for most regions of the world (except Asia), only a small fraction of the potential is actually utilized (see Table 12.1).


Biomass resources, fuel preparation and utilization Table 12.1

319

Biomass energy potentials and usage in 2004 (Parrika 2004)

Biomass potential

EJ/year

Woody biomass Energy crops Straw Other Total potential Usage in 2004

41.6 37.4 17.2 7.6 103.8 39.7

Other estimates (e.g. Hoogwijk et al., 2003), factor in radically changed land use, where additional acreage is utilized. This of course indicates much higher potentials of various biomasses with consideration of land use, food production and population increase. For example, of the order of 1000 EJ/ year could be based on energy crops if land use was to be optimized. It is clear, as the authors also state, that such numbers are associated with considerable uncertainty.

12.2.3 Residual biomass resources As mentioned initially, residual (or waste) resources represent a significant potential. The benefits are at least two-fold: not only does the residual resource serve as feedstock for products much in demand such as electricity and liquid fuels, but using this resource rather than primary resources also serves to mitigate the problem of handling society’s waste streams. Finding good use for some of these can be extremely difficult, and often they end up being landfilled or deposited in other ways. In some situations the amounts of residuals produced serve as a limiting factor on other activities, as is the case for manure and animal farming. To date, there have been some studies on the use of residual resources for energy. In Denmark, for example, it is estimated that there are approximately 400 000 tons of dry matter available annually in the form of residual biomass from industrial processes (Nikolaisen, 2009), comprising potato waste, beet waste, pea pods and plants, coffee waste, cigar and cigarette waste, olive stones, shea nut waste, mash from beer brewing, grain screen waste, carrageenan and pectin. Characteristic of these residues are that they often have a high water content and thus require drying before being used as power plant fuels. However, they are a cheap resource, and the chemical diversity of these residues can be turned into an advantage by appropriate mixing. Furthermore, although this study is based on Danish conditions, the types of industrial processes producing these residues are internationally abundant, and thus the same types of residues are likely to be available in most areas of the world.


320


12.3

Chemical constituents in biomass fuels

Before any biomass can be considered for use as a fuel in large-scale primary energy production, the chemical properties of the biomass must be scrutinized. Not only should there be sufficient carbon and hydrogen for a significant energy yield during the selected conversion process, but also the mineral composition and inorganics such as alkali metals are important, as they impact on operation of the plant using a particular type of fuel. In the following, typical compositions of different biomasses are given. For the primary biomasses such as woody and herbaceous types, there are several factors influencing the content of specific compounds and materials, including soil conditions, fertilization strategy and amount of precipitation. Furthermore, for herbaceous biomasses, leaching due to rainfall after harvesting can drastically reduce the content of some chemical species, mainly chlorine and potassium. This is often indicated by the straw turning grey. In general, it is the herbaceous biomasses, as well as the residual biomasses such as MSW, sludge and manure, that pose problems in terms of composition, rather than the woody biomasses – with the exception of bark. The European Committee for Standardization has published guidelines for maximum contents of nitrogen:

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